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BreitBurn Energy Partners LP (NASDAQ:BBEP)

Q4 2010 Earnings Conference Call

March 9, 2011, 12:00 pm ET

Executives

Greg Brown – EVP and General Counsel

Hal Washburn – CEO

Randy Breitenbach – President

Mark Pease – COO

Jim Jackson – CFO

Analysts

Bernie Colson – Oppenheimer

Adam Lade [ph] – RBC Capital Markets

Chad Potter – RBC Capital Markets

Gary Stromberg – Barclays Capital

Kunal Nainani [ph] – Salient Partners

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the BreitBurn Energy Partners Investors Conference Call. The partnership news release made earlier today is available 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, Wednesday, March 9, 2011. A replay of the call will be accessible until midnight, Wednesday, March 23rd, by dialing 877-870-5176 and entering conference ID 7571007, 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

Hey. Thank you 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 security 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 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 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.

Unpredictable or unknown factors, not discussed in those documents also could have material adverse effects on forward-looking statements. The partnership undertakes no obligation to update publicly any forward-looking statements to reflect new information or events.

And additionally, during the course of today’s discussion management will refer to adjusted EBITDA which is a non-GAAP financial measure and 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 alternative 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.

So, 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 fourth quarter and full year 2010 results. We began 2010 with the resolution to Quicksilver lawsuit and the reinstatement distributions, and have spent the full year focused on our return to normal operations and have had great success.

Our operations team truly delivered in 2010 production levels totaled 6.7 million barrels of oil equivalent at the high-end of guidance. Mark will give you more details on our operational effort shortly.

Our fourth quarter adjusted EBITDA totaled $59.1 million and 2010 adjusted EBITDA was approximately $227 million, which is well above the high-end of our guidance. We continue to focus on controlling expenses in both LOE per Boe and general and administrative costs came in below the low end of 2010 guidance ranges.

We reinstated distributions in the first quarter of 2010 at annualized rate of $1.50 per unit. Over the next three quarters we raised distributions 10% to the most recent fourth quarter 2010 distribution of $1.65 per unit annualized. The combination of these distributions paid and unit price appreciation delivered a total shareholder return in 2010 of greater than 100%.

All in all 2010 was a very solid year for the partnership and we expect 2011 to be similar financially and operationally. We believe we have some excellent drilling opportunities in our asset portfolio and have set a new capital budget target between $70 and $74 million.

We expect production to be approximately 6.5 to 6.9 million barrels of oil equivalent in 2011, an increase over 2010 guidance and we are projecting EBITDA guidance in the range – of $195 million to $205 million, which is also above our 2010 guidance of $190 million to $200 million.

Based on our public guidance for 2011, we expect full year distributable cash flow of approximately $120 million, which assumes maintenance capital expenditures of $40 to $50 million and cash interest expense of $36 to $38 million. And based on our current 1.65 distribution run rate that translates to distribution coverage ratio for the year of approximately 1.3 times and these numbers do not reflect any assumed acquisitions throughout the year which is of course core to our business strategy.

As we’ve done in prior years we will continue to emphasize consistent cash flow generation to support distributions to our unit holder’s, work to maintain grow production by effectively operate their asset, our base properties and efficiently executing our planned capital program and actively pursue acquisition opportunities in line with our growth through acquisition strategy.

Maintaining our financial flexibility and liquidity will remain important focus and in 2011, we’ve already enhanced that flexibility. Net proceeds of approximately $100 million from the 4.945 million unit equity offering we closed in early February used to reduce borrowings on our credit facility.

We believe 2011 will be another strong year for the partnership and we thank our team for their excellent work in 2010 and our investors for their continued support.

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

Randy Breitenbach

Thank you, Hal, and welcome, everyone. I will cover details of our commodity hedging activity and the impact of these derivative instruments our fourth quarter and full year results.

For the fourth quarter of 2010 crude oil and natural gas revenues totaled $99.8 million, compared to $99.6 million in the third quarter, $21.7 million and $22.6 million of the sales totals for the fourth and third quarters of 2010, respectively, were a result of realized gains on commodity derivative instruments.

For full year 2010 crude oil and natural gas revenues were $392.6 million of which $74.8 million were a result of realized gains on our hedges, again demonstrating the value of our strong hedge portfolio.

Our hedges have been especially valuable from a gas standpoint, which accounts for more than half of our production. Our realized natural gas prices for the fourth quarter averaged $7.38 per Mcf, compared with NYMEX natural gas prices of $3.98 per Mcf. On the oil side average realized crude oil and liquid prices were $78.95 per barrel, slightly lower than NYMEX crude oil spot prices of approximately $85.16 per barrel for the same period.

For full year 2010, our realized natural gas price averaged $7.57 per Mcf as compared to NYMEX natural gas price of $4.38 per Mcf and our realized crude oil price average $74.31 per barrel as compared to a NYMEX crude oil spot price of approximately $79.48 per barrel.

Non-cash unrealized losses from commodity derivative instruments for the fourth quarter were $82.3 million, reflecting increases in commodity prices for the period. For full year 2010 non-cash unrealized losses from commodity derivative instruments were $39.7 million.

Consistent with our strategy to mitigate commodity price volatility we continue to opportunistically layer in new hedges. In the fourth quarter we hedged an additional 2.2 million barrels covering oil production from 2011 to 2014 at an average weighted price of $87.63 per barrel and 4.6 million MMBtu’s covering 2013 and 2014 gas production at an average weighted price of $5.70. So far in 2011, we have extended our commodity protection portfolio in the 2015, hedging 1.5 million barrels of 2014 and 2015 production at an average price of $94 and $0.70 per barrel.

An updated presentation of the partnership’s commodity price protection portfolio as of March 9, 2011, will be made available in the Events and Presentation section of the Investor Relations tab on our website.

As we move further into 2011, our hedge portfolio will continue to play an integral role in our overall business strategy. It has been a vital tool for mitigating commodity price volatility, stabilizing revenues and cash flows and supporting our borrowing base. A significant portion of oil and gas volumes are well protected at attractive prices through the next five years.

Assuming the midpoint of 2011 production guidance is held flat, our production is hedged 84% in 2011, 76% in 2012, 72% in 2013, 40% in 2014 and 16% in 2015. Average annual prices during this period range between $80.20 and $96 per barrel for oil and $6 and $8.05 per MMbtu for gas.

More specifically for 2011, our average hedge prices for oil and natural gas are $80.20 and $7.92 and those prices actually improve in 2012 to $87.97 and $8.05 for oil and natural gas, respectively. We will continue to evaluate an opportunistically add-on hedge portfolio in the future.

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

Mark Pease

Thanks, Randy. As Hal mentioned, operationally we had a very strong year in 2010. I’ll run through results at the partnership level and then discuss some of the details by division. In the fourth quarter we produced 1.7 million barrels of oil equivalent, which is just under the prior quarter’s production of 1.74 million barrels of oil equivalent.

Full year production came in at 6.7 million barrels of oil equivalent or 18,400 barrels of oil equivalent per day which is at the high-end of our guidance range and is an increase of about 3%, compared to 2009’s production of 17,900 barrels oil equivalent per day. Our overall production split for the year was approximately 53% natural gas and 47% crude oil and NGLs.

Lease operating expenses and processing fees excluding transportation expenses came in at $29.5 million or $17.37 per Boe for the fourth quarter of 2010. Full year operating expenses came in at $118.5 million or $17.68 per Boe, which is below the low end of our guidance and below 2009 operating costs of $17.90 per Boe. Our operating team continued to successfully focus on lowering costs during 2010.

However, as we said in the past, costs are strongly influenced by the price of oil and natural gas and rising oil prices in the fourth quarter have resulted in upward pressure on the costs of services and materials.

Total oil and gas capital expenditures in the fourth quarter were $16.1 million and oil and gas capital expenditures for the full year were $69.5 million. We thoroughly reviewed our portfolio of opportunities going forward and believe 2011 maintenance capital will be flat to last year’s guidance of $40 to $50 million.

Our total capital for 2011 will be between $70 and $74 million. As we noted in the past, our approach to estimating maintenance capital requirements is very rigorous and based on our reserve data, as well as our long range financial plans.

Let me update you quickly on our year-end reserves before getting into more detailed operational results. As of December 31, 2010, our total estimated proved oil and gas reserves were 118.9 million barrels of oil equivalent. This compares to year-end 2009 reserves of 111.3 million barrels equivalent so we are up 7%. The year end 2010 reserves are split about 65% natural gas and 35% crude oil and 91% of our proved reserves were classified as proved developed.

The standardized measure of net future cash flows from the production of these reserves discounted at 10%, is approximately $1.1 billion using SEC pricing and costs effective for year end 2010 calculations. These prices and costs are held constant throughout the life of the properties.

Of the total estimated proved reserves, 68% were located in Michigan, 12% in California, 10% in Wyoming, 8% in Florida, with remaining 2% in Indiana and Kentucky. Reserves, as of December 31, 2010, were determined primarily using an average WTI price of $79.40 per barrel and an average Henry Hub price of $4.38 per MMBtu. Those compared to average 2009 prices of $61.18 per barrel for WTI and $3.87 per MMBtu at Henry Hub.

Moving onto the performance of our two operating divisions, both divisions delivered solid results this quarter. Production in the eastern division which consists of Michigan, Indiana and Kentucky were strong due to the performance from our broad base of producing wells and also due to the excellent results from our 2010 capital program.

Control of LOVE [ph] was lower than forecast due primarily to the continued focus on cost reductions by the eastern team. One area where they were particularly successful was in reducing compression repair and maintenance costs.

Low gas prices continue to put downward pressure on our costs contributing to the lower than forecast operating expenses and taxes for the eastern division. Capital expenditures in the eastern division for the fourth quarter consisted of one drill well, eight well workovers and five facility optimization projects.

These capital projects added net initial production of about 2.7 million cubic feet equivalent per day. For full year 2010, the eastern division drilled 17 wells, completed 31 workovers and recompletions and completed 11 facility optimization projects. These projects added net initial production of about 10.5 million cubic feet equivalent per day.

Now, shifting to the western division, full year production in western which includes California, Wyoming and Florida was impacted by the delayed completion of the second horizontal well at the Raccoon Point Field in Florida. As we mentioned previously, we plan to drill three additional horizontal wells in the Raccoon Point Field this year.

The first of those three was spud in late December and has reached total depth in a shorter time than either of our first two wells. We are now moving the drilling rig to the next location.

Western division controllable lease operating expense per barrel was lower than forecast due to continued focus on overall spending and in part due to reduced well pulling expenditures in California. Full year 2010 capital in the western division was spent to drill 15 wells and complete 10 workovers and recompletions. These projects added net initial production of about 1750 barrels of oil equivalent per day.

Let me conclude with a few notes on operating guidance. In 2010, we'll be operating under comparable spending levels to 2000 – sorry – in 2011, we'll be operating under comparable spending levels to 2010 and we are forecasting production levels between 6.5 and 6.9 million barrels of oil equivalent.

We anticipate spending approximately 70% of our 2011 capital in the western division where our production is essentially all oil and approximately 30% in our eastern division where production is mainly natural gas. If we plan to drill approximately 40 wells which represents about 60% of our total capital spending, of the 40 wells we plan to drill, 27 are expected to be in Michigan, seven in Wyoming, three in California and three are in Florida.

Similar to last year, due to the timing of some of our key projects and winter weather constraints in Wyoming and Michigan, we will only execute about 20% of our program during the first quarter with most of this work being done in Florida. The majority of our capital activity will take place in the second and third quarters which enables us to much better control costs.

We'll continue to focus rigorously on controlling operating expenses. Additionally, given the flexibility of our balanced asset portfolio, we will continue to evaluate project economics for our oil and gas opportunities as commodity prices change over the course of the year, and we will allocate our capital to the projects that provide the best return for the company.

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

Jim Jackson

Thank you, Mark. I will start by reviewing some more specific results for the quarter and the year and conclude with commentary on our 2011 guidance. Oil and natural gas revenues including realized gains on commodity derivative instruments were fairly flat in the fourth quarter at $99.8 million compared to $99.6 million in the third.

Realized gains on commodity derivative instruments were $21.7 million, down slightly from $22.6 million in the prior quarter. Full year 2010 revenues including $74.8 million of realized gains on commodity derivative instruments totaled $392.6 million.

General and administrative expenses excluding unit based compensation expense were $5.9 million or $3.47 per BOE in the fourth quarter versus $7.2 million or $4.13 per BOE in the third quarter. On a full year basis, G&A costs excluding unit based compensation were $24.5 million compared to $23.7 million in 2009.

While this represents a slight increase, it was below the low end of our guidance range. We had anticipated higher G&A in 2010 due to increased activity compared to the prior year but manage to control costs considerably. Full year G&A excluding unit based compensation was approximately $3.65 per BOE.

Fourth quarter adjusted EBITDA was $59.1 million compared to $60 million in the third quarter. Full year adjusted EBITDA was 22 – $226.9 million – excuse me – well above the high-end of our guidance range.

Production and property taxes totaled $5.6 million in the fourth quarter as compared to $5.1 million in the third quarter. The increase in taxes was principally due to higher oil prices.

Net interest and other financing costs excluding realized and unrealized gains and losses on interest rate swaps for the fourth quarter were $10.8 million compared to $5.1 million in the third quarter. Cash interest expense including realized losses on interest rate swaps totaled $10.8 million in the fourth quarter of 2010.

Full year cash interest expense totaled $30.4 million which is well within our 2010 guidance range of $30 million to $32 million although we expect interest expense to increase in 2011 due to higher interest costs on our senior notes.

We recorded a net loss of $70.9 million or $1.25 per limited partnership unit for the fourth quarter and net income of $34.8 million or $0.61 per unit for full year 2010. The fourth quarter loss was primarily due to significant unrealized losses on commodity derivative instruments of $82.3 million which contributed to a full year unrealized loss on commodity derivative instruments of $39.7 million.

Let me now turn to our liquidity position. Our outstanding long-term debt at the end of the fourth quarter was $528 million and consisted of borrowings of $228 million under our credit facility, $305 million in senior notes and $5 million in unamortized discount on senior notes. As of February 28, we had $122 million outstanding under the credit facility reflecting the $100 million in net proceeds from our recent equity offering.

Now, I will review 2011 guidance which was announced in the press release we issued this morning. We expect 2011 to look very similar to 2010 from both an operational and financial point of view.

We are projecting total capital expenditures for the year to be between $70 million and $74 million. These estimates include maintenance capital expenditures as well as growth capital expenditures.

We define maintenance capital as the estimated amount of investment in capital projects, existing facilities and operations, needed to hold production approximately constant from period to period. For 2011, our guidance for maintenance capital is $40 million to $50 million.

As you know, our calculation for distributable cash flow is adjusted EBITDA minus cash interest expense minus maintenance capital. We expect or we are expecting our 2011 production to be between 6.5 million barrels of oil equivalent and 6.9 million barrels of oil equivalent with production ramping up throughout the year consistent with the timing of our capital program.

We project our production mix to be 48% oil and 52% gas for the year. Average price differentials are expected to be between 89% and 91% for oil and between 100% and 102% for gas.

Our operations team did an excellent job controlling costs in 2010 and that will continue to be their focus in 2011. We expect 2011 lease operating costs to be between $18.50 and $21 per BOE.

These estimated operating costs include lease operating expenses, processing fees and transportation expense. Expected transportation expense totals approximately $6.7 million in 2011 largely attributable to our oil production. Excluding transportation expense, our estimated operating costs range per BOE is approximately $17.50 to $20.

When estimating operating costs for 2011, we are assuming flat $80 oil and $4.25 gas price levels in contrast to the flat $70 oil and $5 gas prices we used for our guidance in 2010. Production taxes are expected to range between 7.5% and 8% for oil and gas revenues. This increase compared to 2010 reflects higher expectations for oil prices and its impact on property values.

Management expects general and administrative expenses excluding unit based compensation in 2011 to be between $26 million and $28 million, a slight increase over our 2010 guidance and equal to approximately $4 per BOE. The partnership expects to generate adjusted EBITDA, a non-GAAP measure, of between $195 million and $205 million in 2011. These expectations are based on a number of operating and other assumptions including commodity prices remaining at or near $80 per barrel for the year and $4.25 per Mcfe for natural gas and reflects the benefits of the partnerships existing hedge portfolio.

We are forecasting at cash interest expense range of $36 million to $38 million on our outstanding borrowings which reflects interest from both our senior notes and our bank credit facility. The interest expense on the bank credit facility assumes a one month LIBOR rate of 1% and includes the impact of interest rate swaps covering approximately $175 million of borrowing at a weighted average rate of 2.23%.

For additional assumptions and a discussion of the build up to adjusted EBITDA from estimated net income, please see our detailed guidance, footnotes in today's release. In conclusion, I’d like to reiterate that 2010 was an outstanding year both operationally and financially.

We exceeded expectations on many metrics, most notably on production, EBITDA, lease operating costs and G&A costs and we demonstrated our ability to quickly and efficiently the equity markets and greatly increased our financial flexibility. We look forward to another great year for the partnership and our investors in 2011.

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 is from Bernie Colson with Oppenheimer.

Bernie Colson – Oppenheimer

Good morning.

Hal Washburn

Good morning, Bernie.

Jim Jackson

Good morning, Bernie.

Bernie Colson – Oppenheimer

So I want to talk a little bit more about the capital budget. It’s $70 million to $74 million total and did you say 60% of that was going to be in drilling?

Hal Washburn

That's correct, 60% for drilling.

Bernie Colson – Oppenheimer

Okay. So 60% for drilling. All right. That's about 43, and then what's the remainder?

Hal Washburn

It is made up of a couple different components. We call them rate generating projects which are that's a mix of recompletions and well stimulations. And then we also have a category in there that we call mandatory expenses but they're a combination of ongoing maintenance expenses that you have to do to keep your operations running and then one-time facility normally facility related expenses that you have to do that are infrequent but things that set your facilities up for properly run for the long-term.

If you're actually looking at the delta in those numbers between what we're spending on – what we’re spending on drilling and then a total number. And we have some significant one-time expenditures in a couple areas, the big ones in Florida and something that is going to set the Florida operation up to produce at higher production volumes for several years in the future.

Bernie Colson – Oppenheimer

Okay. So the – call it the remaining 30 million that’s not drilling is – what portion of that do you think is rate generating versus non-rate generating?

Hal Washburn

The majority of it is non-rate generating because the one-time expenditures that I talked about, I don’t have the specific numbers right here in front of me, but it will be about, if I am thumbing through some papers here, about between 10% and 15% of that number would be rate generating, and the remainder would be the mandatory that I talked about.

Bernie Colson – Oppenheimer

Okay. 10% to 15% of the 70 to 74 or of the remaining 30?

Hal Washburn

10 to 15% of the 70 to 74.

Bernie Colson – Oppenheimer

Okay. Okay. And so the 40 wells that are going to be drilled, I guess, you have $43 million in spends, so an average of a million dollars a well – sorry, but I was hoping that you could repeat where the well breakdown and where they are going to be drilled? I know you did that but I just I couldn’t catch it all?

Hal Washburn

I have got it right here. It’s 27 – are in Michigan.

Bernie Colson – Oppenheimer

Yep.

Hal Washburn

Three in California, three in Florida, and whatever the difference is, seven in Wyoming.

Bernie Colson – Oppenheimer

Seven in Wyoming. Okay. Would you care at all to share some information about well drilling costs by region? Are we talking – I think the Florida wells are clearly more expensive, but – ?

Hal Washburn

Yeah. That’s more expensive. It’s a little bit difficult to give you specific numbers, but for the most part the drilling we’re doing in Michigan shallow gas and those are wells that depending on whether it’s a re-entry of existing well or a grassroots location, they run between $200,000 and $500,000.

We do have a couple of deep wells in Michigan, and those are more expensive. Florida, depends again on whether we’re doing a re-entry or grassroots well. Those run between $6 million and $9 million again depending on the specifics and Wyoming as with other areas is somewhat field specific, but usually somewhere between $900,000 and $2 million.

Bernie Colson – Oppenheimer

Okay. All right. Okay. So, I guess out of the majority of your drilling portion of your budget is going to be spent in the Pan and floor [ph] Panhandle region there?

Hal Washburn

That’s correct.

Bernie Colson – Oppenheimer

Like 20 – okay. Seems right. Okay. And then would there be any data you can provide about expectations of production or IT rates by the different regions or is that not something you can go into details about?

Hal Washburn

We don’t go into the detail by different regions. What we try to do is we have got a portfolio of fields and areas and opportunities, and as we go through our programs each year, some often turn out better than what we forecast; some turn out not as well as what we forecast, so we look at the total.

Bernie Colson – Oppenheimer

Okay. Okay. Last question, I promise. The depletion expense for the quarter, can you talk something about what is driving that?

Larry Smith

The depletion expense for the quarter was up. We had a couple of adjustments that we made. We had a couple of fields in our Michigan locations due to the economics that we had a write-down on. We also had a couple of leases that expired that had some investments that was allocated to it for some probable re severs. So, that’s what’s really driving that number up. They’re one-time adjustments.

Hal Washburn

That was Larry Smith, our controller.

Bernie Colson – Oppenheimer

Okay. Okay. So I guess – it kind of ran in the 20, 25 range for the first three quarters of the year and then went up to 33 or whatever, so that expectation that’s going to be kind of in that 20, 25 range on a quarterly basis in 2011 or –?

Hal Washburn

That’s the expectation, yes.

Bernie Colson – Oppenheimer

Okay. All right. Thanks a lot.

Randy Breitenbach

Thank you, Bernie.

Hal Washburn

Thanks, Bernie.

Randy Breitenbach

And Bernie, one comment. The wells we’re drilling in Florida are not in the Panhandle. They’re down in the southern trend which is South Florida.

Bernie Colson – Oppenheimer

I am sorry. Sorry about that.

Randy Breitenbach

No problem.

Bernie Colson – Oppenheimer

Thanks.

Operator

And our next question is from Adam Lade [ph] with RBC Capital Markets.

Hal Washburn

How are you doing, Adam?

Randy Breitenbach

Hi, Adam.

Adam Lade – RBC Capital Markets

Quick question (inaudible)

Hal Washburn

Adam, we’re having a hard time hearing you?

Adam Lade – RBC Capital Markets

Sorry about that. Is that better?

Hal Washburn

Much better.

Randy Breitenbach

Much better.

Adam Lade – RBC Capital Markets

I am wondering if you can give us a little bit more color on the reserve change, how much was extensions, discoveries versus price revisions?

Mark Pease

Sure. You bet. The majority of that amount in fact over half of it was due to higher pricing, and then if you go through and look at the increases due to drilling workovers and re-completions and acquisitions; we did some small acquisitions during the year. It’s about – always about 40% of that number.

Adam Lade – RBC Capital Markets

Okay. And then you did mention that acquisitions were core of your business strategy. Is there anything that we might be expecting any time soon?

Hal Washburn

Adam, this is Hal. We are always looking at acquisitions. We are very active in the market. At any one time we are looking at a lot of different deals. There is nothing that we are on the verge of announcing, but we are constantly in the market and expect to continue to make acquisitions as we have over the last 20 plus years.

Adam Lade – RBC Capital Markets

Of the size of the things you might be looking at?

Hal Washburn

Well Adam, in our core areas we look at anything. We’re doing a whole bunch of non-op and royalty interest acquisitions that could easily be sub million dollars, very, very small deals, up to deals. And we have a lot of financial flexibility today, so we’re looking at deals that could easily be a couple of hundred million dollars or more. That’s our fair way, you know, the middle of fair way is kind of $150 million, $250 million acquisitions.

Adam Lade – RBC Capital Markets

Okay. That’s great. Thanks.

Operator

(Operator Instructions) Our next question is from Chad Potter with RBC Capital Markets.

Chad Potter – RBC Capital Markets

Good morning, guys.

Hal Washburn

Hi, Chad.

Randy Breitenbach

Hi, Chad.

Chad Potter – RBC Capital Markets

Question, in the footnotes to your guidance table you mentioned the assumptions are based using $80 oil; obviously oil is much higher than that currently. Could we assume that CapEx and maybe even production could go higher in the sense that you might keep activity running higher to the extent oil prices remain elevated?

Hal Washburn

You know, Chad, we are constantly looking at the opportunity set. We announced our capital program earlier this year for 2011. Prices went up dramatically since then. So we are constantly evaluating. This is our plan today, but as prices hold at this level you would – should assume that we will be constantly looking at the program and evaluating it.

Chad Potter – RBC Capital Markets

Understood. Do we have – I don’t think if I missed it, any update on the latest Florida well, I think, in the CapEx guidance press release you guys talked about essentially discussing it during this call?

Randy Breitenbach

Sure. We’re not giving a specific guidance on the well production or update on that. What we have said is that we completed – we got the well to total depth in less time than either of the first two wells. We are moving the rig to the next well currently, and I think it’s fair to say we expect to see production sometime early in the next quarter on this well.

There is a high degree of variability among these wells. We have had wells come in at over 1,200 barrels a day and the second well at kind of 200 to 300 barrels a day. So we expect something in that range and are moving forward on our plans there. So we are pleased with our results so far, and there is a lot of variability in the field. These are consistent with what we have seen to date and what we expect going forward.

Chad Potter – RBC Capital Markets

Okay. Appreciate that. And I guess one last question, haven’t heard anything on the calling but of late, just kind of curious what you might be hearing in the field? I believe you had some other industry wells drilled if there is any update there what you have seen?

Hal Washburn

Everybody who is drilling is keeping the results very tight. There are a lot of – obviously a lot of – there is a lot of interest, but we don’t have any solid results that we do understand that the first EnCana well may be turned into production soon after having built a pretty significant pipeline, but we don’t have any results that are public that we’re aware of – or any results that are public that we’re aware of.

Chad Potter – RBC Capital Markets

Have you participated in any wells that may not be public currently?

Randy Breitenbach

No.

Hal Washburn

No. We have not participated in any wells. Our acreage is virtually all HBP, and at this point we’re watching others seeing how their wells work out.

Chad Potter – RBC Capital Markets

And I guess one last question and then just following onto that. Any continuing discussions as far as monetization or is that kind of Don Paul [ph] is waiting for industry results?

Randy Breitenbach

I think that’s really on hold until some wells are drilled and some gases sold, gas and liquids. At this point we don’t have any ongoing discussions.

Chad Potter – RBC Capital Markets

Appreciate it. Thanks, guys.

Hal Washburn

Thanks, Chad.

Randy Breitenbach

Thank you.

Operator

Our next question is from Gary Stromberg with Barclays Capital.

Gary Stromberg – Barclays Capital

Hi. Good morning.

Hal Washburn

Hi, Gary.

Gary Stromberg – Barclays Capital

Just in terms of acquisitions, the $150 million to $250 million sweet spot you talked about, I assume that would be debt finance? Can you just talk about financing strategy of acquisitions?

Hal Washburn

Sure.

Jim Jackson

Gary, it’s Jim. Happy to. We look to finance acquisitions consistent with how the business is financed today and we actually underwrite them in that regard, which is, very close to a balance of half debt and half equity financed on a long-term basis.

And clearly in the context of the dynamics of a deal we might do something that was a 100% debt financed, but again we – our outlook for capital structure is to have a balance or a slight bias towards equity financing, and we underwrite acquisitions accordingly. So –

Gary Stromberg – Barclays Capital

Okay. That’s helpful. Was the equity offering that was done in February, was that in anticipation of a deal or is that just resetting to where you’re more comfortable in leverage?

Jim Jackson

It was in anticipation of pursuing our acquisition strategy. If you recall, we were very specific in 2009 and early 2010 about getting to a target leverage ratio before we reinstated distribution, et cetera. We were well below that – and at that level or below it before we reinstated distributions and $100 million of equity takes us down into lower leverage levels.

And so we’ll continue to look at acquisitions and that was an opportunistic financing to give us the ability to move quickly.

Gary Stromberg – Barclays Capital

Okay, that’s helpful. And then one last housekeeping. Borrowing base, is it $658.8 million, do I have that right?

Jim Jackson

That’s correct.

Gary Stromberg – Barclays Capital

Great. That’s all I had. Thank you.

Jim Jackson

Thanks, Gary.

Operator

(Operator Instructions) Our next question comes from James (inaudible).

James

Hi, guys. Long time no speak.

Hal Washburn

Hey, James.

James

I guess my question was the same; I guess it has been answered about the timing of the equity offering relative to acquisition. So, I guess, I have no question. Thank you very much.

Hal Washburn

Nice talking to you, James.

Operator

And our next question is from Kunal Nainani [ph] with Salient Partners.

Kunal Nainani – Salient Partners

Hey, good morning, guys.

Hal Washburn

How are you doing?

Mark Pease

Hi, Kunal.

Kunal Nainani – Salient Partners

Just a quick question on the three wells that you – drilled in Florida, I was wondering if you guys could detail a little bit more specificity around the timing of those wells?

Mark Pease

This is Mark. As Hal mentioned we’ve TD’d the third well and are in the process of moving the drilling rig to our – third well, sorry. So, it will be the first of the three wells you referenced. So we TD’d that first well for 2011. We are in the process of moving the drilling rig to the second well; it is a fairly lengthy process to go through the completion so on. So we expect the first well to come on production in the early second quarter.

As far as the next two wells, we think we’ll see – we had – the drilling timing on this first well was very good shorter than what we have seen out there so far, and we are certainly going to strive to, sort of, keep that same drilling timing. Could be a little bit better than that; may not be quite so good, but if you look at the timing of spudding that well in late December and then coming on early second quarter we have similar timing on the next two wells.

Kunal Nainani – Salient Partners

Okay. Understood. My other questions have been answered, so I will drop off for the next in queue. Thanks.

Hal Washburn

Thanks.

Mark Pease

Thanks, Kunal.

Operator

And that’s all the time we have for questions today. Mr. Washburn, I will turn the call back over to you for any closing remarks.

Hal Washburn

Thank you. 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 that concludes today's conference call. We thank you for your participation.

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