BreitBurn Energy Partners' CEO Discusses Q2 2012 Results - Earnings Call Transcript

 |  About: Breitburn Energy Partners LP (BBEP)
by: SA Transcripts

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

Q2 2012 Earnings Call

August 7, 2012 1:00 pm ET


Greg Brown - EVP and General Counsel

Hal Washburn - CEO

Randy Breitenbach - President

Mark Pease - COO

Jim Jackson - CFO


Praneeth Satish - Wells Fargo

Ethan Bellamy - Baird

Gary Stromberg - Barclays

Adam Leight - RBC Capital Market

John Ragozzino - RBC Capital Markets

Jeff Robertson - Barclays

Kevin Smith - Raymond James


Welcome to the BreitBurn Energy Partners inventor conference call. The Partnership's new release made earlier today is available from its website at (Operator Instructions) I would now like to turn this call over to Greg Brown, Executive Vice President and General Counsel of BreitBurn.

Greg Brown

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 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 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 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 in our quarterly reports on From 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 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 publicly traded partnership's or limited liability companies, because all companies may not calculate adjusted EBITDA in the same manner.

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 second quarter of 2012. We had a strong second quarter marked by consistent operating and financial performance, sequential distribution growth and the successful closing of three acquisitions.

Based on our ongoing review of our legacy and new acquired assets, we are announcing today a substantial increase in our capital program for the remainder of 2012, as well as updating our second half 2012 guidance.

Let me start by discussing a few key quarterly highlights. During the second quarter we produced 1.953 million Boe of oil and natural gas, which is up 18% from the second quarter of 2011, and generated $66.3 million of adjusted EBITDA, which represents a 28% increase from the second quarter of 2011 and a quarterly record for the Partnership. These results reflect the quality of our underlying assets, our ongoing focus on efficient operations and the success of our growth through acquisition strategy.

Turning to our distributions, we're pleased to have announced the second quarter distribution of $0.46 per unit or $1.84 on an annualized basis. This represents a 9% increase from second quarter 2011 distributions. Further, this marks our ninth consecutive quarterly distribution increase.

I'd like to talk briefly about our three most recent acquisitions that we announced during the second quarter. On June 28, 2012, we completed the bolt-on acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from NiMin for approximately $93 million, subject to customary post-closing adjustments.

On July 2, 2012, we completed two separate acquisitions of oil and natural gas properties located in Permian Basin in Texas from Element and CrownRock for approximately $150 million and $70 million, respectively, also subject to customary post-closing adjustments.

The acquired assets, characterized by long-live reserves with significant original oil in place and a large number of potential drilling locations are excellent additions to our portfolio. The representative of the type of assets we are actively targeting for the balance of 2012 and beyond.

In conjunction with the acquisitions and consistent with our hedging strategy, we entered into very attractive hedge positions, which we will discuss in more detail later. As part of acquisition integration and given the continued positive drilling results from our legacy assets, I am very pleased to announce that we are substantially increasing the size and scope of our 2012 capital program for the second time this year.

If you recall, our original capital expenditure guidance announced in February of approximately $68 million was raised by $19 million in May, principally to pursue low risk drilling projects that had very attractive economics on our legacy California oil properties.

Today, we are announcing a further increase of $50 million, which will increase our total 2012 capital program to approximately $137 million. This additional $50 million will be spent developing our newly acquired assets and pursuing primarily oil projects that we've identified in our legacy assets. Mark will provide more details about the updated capital program later.

As a result, closing our three latest acquisitions and further expanding the capital program, we're also updating our guidance for the second half of 2012. We are increasing our full year production target to between $8.3 million and $8.6 million Boe. And we're increasing our full year adjusted EBITDA target to between $280 million and $290 million. Jim, will discuss our updated second half 2012 guidance in more detail later in the call.

I'd like to conclude by sharing some thoughts on the recent commodity price weakness. We have seen significant volatility in commodity prices this quarter, with natural gas prices falling to historical lows in the sub $2 per MMBtu area, and oil prices declining from over $100 per barrel to below $80 per barrel.

As with any company, with exposure to commodity prices, volatility and sustained price declines can impact our business. To mitigate the effects of commodity price volatility and distribution stability, particularly in the outer years, the Partnership's strategy is to continue to grow through acquisitions.

We remain fully committed to growing our distributions and coverage ratio over time. Our strategy is quite simple and remains unchanged, since when we started the company in the late 80s.

We will continue to review our expanding portfolio of oil and gas assets for attractive development opportunities, and continue to grow the portfolio through acquisitions. We're well-positioned to execute this strategy, which supports continued distribution growth in the volatile price environment.

As we've mentioned before, we're targeting $300 million to $500 million in acquisitions this year and are well-positioned to reach that target. We have significant financial flexibility and we expect M&A activity to accelerate as we approach the fourth quarter.

In just the first half of this year, we've already met our target by completing $313 million in acquisitions and are well on our way to reach the high-end of that target, as we continue to evaluate new opportunities through the remainder of the year.

In just the past 12 months, we've completed five acquisitions totaling over $650 million and increased total estimated proved reserves by approximately 57 million Boe and production by approximately 7,300 Boe per day.

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

Mark Pease

Thanks Hal. I'll run through the results at the Partnership level and then discuss some of the details by division. In the second quarter, we produced 1.953 million barrels of oil equivalent, which is within our original guidance range.

This was slightly lower than the prior-quarter production of 1.987 million barrels of oil equivalent, primarily due to the expected reversion of the interest in two of our California fields, which occurred on April 1. And we also have some mechanical downtime in Michigan and Florida.

For the trailing 12 months, second quarter 2012 production represented a 19% increase from second quarter 2011 production levels. The production split for the second quarter was approximately 58% natural gas and 42% oil. NGL production made less than 3% of total production. With the increased capital program, we expect liquids production to grow to approximately 50% of total production by yearend.

For the second quarter, lease operating expenses, including processing fees and transportation expenses were $39.1 million or $20.03 per Boe, which is within our original guidance range. This is up from $19.16 per Boe in the first quarter of this year. The increase was primarily due to higher well workover expense and increases in fuel and utility cost in Florida. For the full year, excluding the acquisitions, we expect lease operating cost to remain within our original guidance.

Capital expenditure from our oil and gas activities in the second quarter were approximately $28 million, up significantly from the prior-quarter expenditures of $16 million. The increase is mainly due to increased drilling on oil projects in our California properties.

As Hal mentioned earlier, as a result of the 2012 capital development plans for the newly acquired assets and the positive drilling results in our legacy properties, we have increased our capital program for the second time this year by $50 million, to a total of approximately $137 million for the full year 2012.

Of the $50 million increase, approximately $30 million will be spent on the new properties acquired in Texas and Wyoming, and about $20 million will be spent on our legacy assets in our Northern and Southern Divisions. About $45 million or 90% of the additional capital will be spent in drilling new wells.

The proposed drilling projects for the newly acquired assets consist of 19 non-operated infill wells in the Wolfberry Trend and nine operated infill wells in Northern Wyoming. The increased capital program for our legacy assets added five wells in Southwest Wyoming, two wells in Northern Wyoming, two wells in Michigan, and one well in Florida.

There are also a numerous recompletions, well workovers and one facility optimization projects that will be done. Due to current commodity prices, we have put a strong focus on identifying more oil opportunities. Of the $45 million that was added for drilling, $43.8 million will be staying on oil wells.

Now, let's discuss the second quarter performance by two operating divisions. Second quarter production in the Northern Division, which consists of Michigan, Wyoming, Indiana and Kentucky was about 1.5 million barrels of oil equivalent, which is essentially flat compared to the prior quarter's production.

Second quarter per unit leased operating expenses for the Northern Division were $1.80 per Mcf equivalent or 9% lower in the prior quarter, due to lower maintenance activity during the winter and spring months. Capital spending in the Northern Division for the second quarter totaled approximately $5.5 million and consisted of 20 workovers and two facility optimization projects.

Capital activity this quarter was successful and having incremental net production of 1.2 million cubic feet equivalent per day. The results of the capital program in terms of both dollars spent and the incremental production achieved were consistent with our pre-work expectations.

In the Southern Division, which includes California and Florida, and will include Texas, starting in the third quarter, second quarter production was 446,000 barrels of oil equivalent, which was down slightly compared to the first quarter of 2012 production of approximately 471,000 barrels of oil equivalent, primarily due to the reversion and interest in two of our California fields and mechanical downtime on our best well in Florida. At the end of July, that Florida well was back on production and producing at the expected rate of about 400 barrels of oil per day.

Lease operating expenses for the quarter averaged for $42.32 per barrel of oil equivalent, which was higher than expected due to abnormally higher well work in California and Florida. We expect third quarter expenses to be lower and full year expenses to remain within guidance.

Capital spending in the Southern Division for the second quarter totaled approximately $22 million, which was above Q1 expenditures of $12.1 million mainly due to the increased drilling program in Santa Fe Springs.

Six oil wells were drilled and completed in California and Florida. The actual well cost came in slightly below forecast and the actual 30 day initial production rates were above the forecasted rate. So we had a very good quarter in California.

Now, I'd like to give an update on the NiMin, Element and CrownRock acquisitions we've just closed. The NiMin acquisition closed on June 28, 2012. As discussed on our last earnings call, the property is 100% oil production and located in the Big Horn Basin, close to our legacy properties, where we have a significant presence and strong operating team.

The NiMin fields are all operated by BreitBurn and we took over operations on the closing date. Integration of these assets is progressing well and we expect to start our first well in late September, and we plan to pickup the second rig in the fourth quarter as we have numerous infill locations to drill. This acquisition was very much of bolt-on to our existing operations.

Now, let's discuss the Element and CrownRock acquisitions, which both closed on July 2, 2012. These were significant for BreitBurn, as they represented our entry into the very prolific Permian Basin with the unique deal structure. BreitBurn will operate the existing producers and will assume operations on November 1, 2012. This will allow sufficient time for us to move transition.

CrownRock will continue to be the operator for the drilling of new wells. This has significant advantages and the CrownRock has drilling rigs and services under existing contracts, so there won't be operating activity. And CrownRock is recognized as a very good operator. Looking closely with them, we'll greatly accelerate our running curve in an area where we did not have a presence prior to the acquisitions.

We are very pleased with these acquisitions and the operating structure. And believe our presence in area will facilitate future acquisitions.

One other comment about the Permian acquisitions, there is some high Btu associated gas production that will add some NGL production. However, the current production from these added NGLs is just under 1% of BreitBurn's daily total production. So it's a very small piece of our business. All-in-all, it's been a very solid quarter for the company and a very exciting quarter.

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

Randy Breitenbach

Thanks Mark. I'll start by addressing our second quarter commodity hedging activity and provide an overview of the impact of these derivative instruments on our financial results. For the second quarter of 2012, crude oil, natural gas and NGL revenues totaled $95 million compared to $94 million in the first quarter of 2012.

The increase was primarily due to higher average crude oil prices offsetting lower realized natural gas prices. Total revenues including realized gains on commodity derivative instruments were $120 million in the second quarter compared to $112 million in the first quarter 2012.

Our hedging activity continues to play an integral role in mitigating commodity price volatility, particularly with regard to natural gas. Our natural gas prices for the second quarter averaged $5.74 per Mcf compared with Henry Hub natural gas spot prices of $2.29 per Mcf.

On the oil side, average realized crude oil and liquids prices were $92.08 per barrel compared to NYMEX crude oil spot prices of approximately $93.29 per barrel for the same period. Brent crude oil spot prices, which are an important benchmark for our California oil production, averaged $108.04 per barrel in the second quarter of 2012 compared to $118.71 in the first quarter of 2012.

Non-cash unrealized gains from commodity derivative instruments for the second quarter were $82.2 million, primarily due to a significant decrease in oil future prices during the quarter, partially offset by an increase in natural gas future prices.

Consistent with our hedging strategy of acquisitions to lock in the expected economics, we immediately entered into new hedges for the NiMin, Element and CrownRock acquisitions. On May 10, 2012, we entered into swaptions contracts that provided an option to hedge a total of 322,646 barrels of future crude oil production associated with the Element acquisition under current NYMEX WTI market prices ranging from $98.35 per barrel in 2012 to $87.80 per barrel in 2017.

On the same day, we entered into swaption contracts that provided an option to hedge a totaled of 311,839 barrels of future crude oil production associated with the CrownRock acquisition at current NYMEX WTI market prices ranging from $98.35 per barrel in 2012 to $87.80 per barrel in 2017. The Partnership exercised these swaptions on July 16, 2012.

Similarly, the Partnership exercised the swaption contracts associated with the NiMin acquisition on July 31, 2012. These contracts covered 510,168 barrels of future crude oil production at current NYMEX WTI market prices ranging from $104.80 per barrel in 2012 to $88.45 per barrel in 2017. With the exercise of the swaption contracts related to our most recent three acquisitions, the Partnership's further strengthened its hedge portfolio into 2017 at attractive prices.

As you know, we continue to opportunistically layer in new hedges. In addition to swaptions contracts that were exercised for the recent acquisitions, we also entered into oil swap contracts hedging 730,000 barrels of oil production for a period covering 2014 through 2016 at an average price of $96.39 per barrel. We also had a natural gas swaps inputs covering $18.6 million Btu from 2014 through 2016, at an average price of $4.30 per MMBtu, providing significant price support for both oil and gas now through 2016.

Assuming the midpoint of our updated 2012 production guidance of $8.3 million to $8.6 million Boe is held flat. Our production is hedged at 75% in the second half 2012, 74% in 2013, 69% in 2014, 66% in 2015, and 20% in 2016. Average annual prices during this period range from $88.12 and $99.96 per barrel per oil, and $4.18 and $7.10 per MMBtu for 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 August 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 over to Jim, who will provide you with additional details of our financial performance and updated guidance. Jim?

Jim Jackson

Thank you, Randy. Total revenues including unrealized gains and losses recorded during the period were $203.2 million in the second quarter. Our second quarter revenues included $25.1 million in realized gains on commodity derivative instruments, and $82.2 million in non-cash unrealized gains on commodity derivative instruments.

We recorded net income of $92.5 million or $1.29 per diluted common unit in the second quarter of 2012, as compared to a net loss of $50 million or $0.76 per diluted common unit in the prior quarter. The increase in net incomes was primarily due to realized and unrealized gains on commodity derivative instruments in the second quarter compared to the prior quarter.

As Randy mentioned, oil and natural gas sales revenues, including realized gains and losses on commodity derivative instruments were $120 million in the second quarter of 2012, up from $112 million in the first quarter.

General and administrative expenses, excluding non-cash unit-based compensation expense were $7.3 million or $3.75 per Boe in the second quarter of 2012 versus $8.1 million or $4.07 per Boe in the first quarter of the year. But declined in the second quarter, generally reflects the seasonal nature of certain G&A expenses mainly accounting and audit fees, which are typically waited towards the first quarter.

It was a record quarter for profitability and second quarter adjusted EBITDA level of $66.3 million, up from $61.4 million in the prior quarter. Production and property taxes totaled $6.5 million in the second quarter, down from $7.6 million in the prior quarter, primarily due to lower oil and natural gas prices and slightly lower production.

Net interest and other financing costs, excluding realized and unrealized gains and losses on interest rate swaps were $14.1 million in the second quarter compared to $13.8 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 $13.6 million in the second quarter of 2012 as compared to $13.2 million in the prior quarter.

As for our liquidity position, our outstanding debt balance as of June 30, 2012, was approximately $774 million and consisted of borrowings of $225 million under our credit facility, and approximately $545 million in senior notes.

As of today, we have $416 million in total borrowings outstanding under our credit facility, which has a borrowing base limit of $850 million. We currently have approximately $434 million of additional borrowing capacity under the facility. And amounts currently outstanding include amounts borrowed from the Element and CrownRock acquisitions, which closed in early July.

Now, I'll review our new guidance for the second half of 2012 as released earlier this morning. As Hal mentioned, second half of 2012 production guidance reflects the substantial increased 2012 capital program and the impacts of the recently completed NiMin, Element and CrownRock acquisition.

We are projecting total capital expenditures for the second half of 2012 of between $90 million and $94 million dollars, which increases our full year 2012 capital program to approximately $137 million.

We are also expecting second half 2012 total production to be between $4.4 million and $4.7 million Boe, which increases our full year 2012 expected production to between approximately $8.3 million and $8.6 million Boe. We project our production mix to be 53% gas and 47% oil for the second half of the year.

In addition our California oil production representing approximately 30% of total second half 2012 oil production is expected to be sold based on Brent pricing. Average oil price differentials for the second half of 2012 are expected to be between 88% and 90% for both WTI and Brent crude oil. Average gas price differentials for the second half of 2012 are expected to be between 108% and 110%.

Our operations team will continue to focus on controlling costs in 2012. We expect operating cost for the second half of 2012 to be between $18 and $20 per Boe. These estimates in operating cost include lease operating expenses, processing fees and transportation expenses.

Expected transportation expense totals approximately $3.4 million for the second half of 2012, largely attributable to our Florida production. Excluding transportation expense, our estimated operating cost per Boe are expected to range between $70.25 and $19.25 per Boe.

When estimating operating cost for the second half of 2012, we are assuming flat $85 per barrel WTI crude oil pricing, $100 per barrel Brent crude oil pricing, and $3 per Mcfe gas price levels. Operating costs generally move with commodity prices, but do not typically increase or decrease as rapidly as commodity prices.

Production taxes for the second half of 2012 are expected to range between 8% and 9% of oil and gas revenues. We expect general and administrative expenses, excluding unit-based compensation to be between $15 million and $17 million for the second half of 2012 or approximately $3.52 per Boe based upon the midpoint of our production guidance range.

The Partnership expects to generate second half 2012 adjusted EBITDA, a non-GAAP measure, of between $155 million and $165 million. On a full year basis, we expect adjusted EBITDA to range between $280 million and $290 million. These expectations are based on a number of operating and other assumptions, including commodity prices remaining at or near oil and gas price levels mentioned earlier, and reflect the benefits of the Partnership's existing hedge portfolio.

We are forecasting cash interest expense range of $32 million to $34 million on our outstanding borrowings for the second of the 2012, which reflects interest of 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 $192 million of borrowings at a weighted average swap rate of 1.84%.

For the second half of 2012, our guidance for maintenance capital, which we define as the estimated amount of investment in capital projects and obligatory spending on existing facilities, and operations needed to hold production approximately constant from period-to-period, is $35 million.

But based upon our updated second half guidance, we estimate our total distributable cash flow to be approximately $92 million for the second half of 2012, which results in a distributable cash flow per unit coverage ratio of approximately 1.4 times based on our current distribution run rate of $1.84 per unit. This estimate assumes commodity prices of $85 per barrel for WTI, $100 per barrel for Brent, and $3 per Mcf for gas, and assumes no additional acquisitions for the remainder of 2012.

In conclusion, I'd like to reiterate that we had a very strong second quarter. We will continue to grow organically by pursuing attractive development opportunities in our portfolio, and through accretive acquisitions to support ongoing distribution growth. We look forward to a strong second half of 2012, and we thank our unit holders for their continued support.

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

Question-and-Answer Session


(Operator Instructions) And the first question comes from Praneeth Satish with Wells Fargo.

Praneeth Satish - Wells Fargo

Just two quick questions, first, are you seeing any infrastructure constraints on the crude side that would impact your production targets at all, especially in the Permian Basin.

Mark Pease

We had a little bit constraint on the natural gas side. Actually the well is producing casing head gas, that's been addressed. So we do not believe there is going to be an issue going forward.

Praneeth Satish - Wells Fargo

As we look to 2013, I know it's early but can you give a preliminary sense as to what capital spending could look like. Is it fair to assume there will be at least as much as 2012?

Jim Jackson

Yes, I think it is too early to look. We haven't started our capital planning for 2013, but I don't think that you could expect to see a meaningful difference from kind of where we're running today, second half of 2012.


And the next question comes from Ethan Bellamy with Baird.

Ethan Bellamy - Baird

Jim, what is the $5 million of other in the guidance?

Jim Jackson

It's just a combination of couple of other things, other revenue, small expenses, frankly without stop wanting to make that footnote price as long as it was. We just abbreviated that, Ethan.

Ethan Bellamy - Baird

Mark, what's the pro forma weighted average decline rate of PDP for the year and maybe looking forward?

Mark Pease

Well, I'll answer your couple of queries. Because of the properties that we just acquired, the new wells are all hyperbolic declines. Again, these incremental properties have declines from the first year that are in the 20% to 30% range.

The second year drops down in there and the second year's there fall into mid-teens and then they get down to the high single-digits. So if you look at our base production, our base production is mid-single range, probably, between 8% to 9% for our base production. As I layer on these new properties and new wells, we're probably in the 12% to 13% for the first year.

Ethan Bellamy - Baird

How many marine shipments add up Florida, would you expect to hit this quarter?

Mark Pease

We're actually expecting two this quarter.

Ethan Bellamy - Baird

So maybe a downtick in the fourth quarter, then?

Hal Washburn

Well, I'm not sure that's the case. We would expect two per quarter, we were short in third quarter, and sold two in the second. We expect to sell two each quarter, and should at some point catch up.

Ethan Bellamy - Baird

Few guys of VNR did a monthly distribution strategy, is that having an appeal to use, something you've looked at?

Jim Jackson

Not really, I mean if we've looked at it, and we've thought about, I know in Canada they did monthly distributions as part of normal course. But at this point, we'd like the quarterly distributions, and hope to see a real benefit to it, but we're continuing to monitor. And if they become attractive and more of our peers go monthly, we'll certainly evaluate.

Ethan Bellamy - Baird

And then I think, you answer this as no, but I just want to check that refinery rate at Chevron, that do anything to the California oil market in terms of realizations?

Mark Pease

Not that we're aware of.


And the next question comes from Gary Stromberg with Barclays.

Gary Stromberg - Barclays

Sounds like the M&A pipeline, is going to remain active, you talked about in the last twelve months, completing $650 million in acquisitions. And I think over that time, you issued of around 260 million in units, it's a 40% of fund rate. What should we think about going forward in terms of funding debt versus equity for acquisitions?

Jim Jackson

We continue to underwrite acquisitions assuming they are funded on kind of a normalized capital structure for BreitBurn, which is call at 50% equity and a plus or minus 50% debt, with approximately 17% of being a long-term debt. Though, we're always be acquiring, we're always be looking to out financing, but when we underwrite deals, we underwrite them on a normalize capital structure.

Gary Stromberg - Barclays

And is there a target leverage that you're shooting for or is it just 50-50 leverage overall?

Jim Jackson

We think about it more in terms of debt to LTM EBITDA, and we've always said that, we generally like to run the business between 2.5 and 3 times leverage, that sort of on a long-term average, obviously in the context of acquisitions, where we're immediately funding them off to the bank, revolver and before we get to turn them out, leverage will get a little north of the three times number, probably for some period of time.

But when it's above three times, we'll be looking at getting it below, and when it's below, we will be looking at acquiring and it will end up little higher. So we'll move around that range for better or for worse.

Gary Stromberg - Barclays

And then can you just repeat what you had drawn currently and what is available?

Jim Jackson

As of yesterday, we had $416 million drawn on the facility, and it's an $850 million borrowing base currently. So we have $434 million of additional capacity.

Gary Stromberg - Barclays

And when is your next predetermination?

Jim Jackson

Next predetermination will be in October. I'd also point out that the current borrowing base of $850 million doesn't reflect the benefit of having added any of the recent acquisitions.

Gary Stromberg - Barclays

So is it your expectation that $850 million could go higher in October?

Jim Jackson



Moving on to, Adam Leight with RBC Capital Market.

Adam Leight - RBC Capital Market

I have couple of follow-ups on those. You obviously have got a lot of headroom under the revolver, which are at comfort level with the number going up, significantly with your cash flow outspend?

Jim Jackson

I think we're just digesting the three acquisitions. We're looking to accelerate capital into the end of the year, based upon where we are currently. We're closer to just a little north of three times leverage pro forma for the effect of the three acquisitions. As I said earlier, if we were to get too far north of three times, that's an area where we'll really start to focus on de-levering one way or another, there are a host of ways to do that obviously.

So I think once we get into the or if anybody who gets into the 3.5 or 3.75 times leverage area, probably out will be a little more concerned on that leverage, certainly then we are today. So we'll keep an eye on that and we'll look to adjust accordingly.

Adam Leight - RBC Capital Market

On the acquisitions front, you said you're digesting. Are you digesting operationally, or are you taking rest, or do you think you alluded to more that you hope to get done. Is there anything in the works and if you are retargeting more within the same areas, particularly maybe adding in taxes or would you be looking at new areas as well?

Hal Washburn

No. We obviously can't comment on pending from acquisitions, but we can say the pipeline is full. We are in the market. We're not taking a break. One of the nice things about the Permian basin acquisition is that we didn't have to jump into a large scale development program. We were able to leverage CrownRock ongoing operations in the basins, and then the NiMin acquisition was a real bolt to the fields immediately adjoining and adjacent to our existing operations.

So neither one of those were operationally intense, and neither required or none of the three required a large expansion of operations for us. So we are looking at acquisitions within our areas of operations.

We'd love do more in California. We're obviously looking quite a bit in the Permian and the Rockies. But we're not limited to those areas. As we said pretty consistently, we look for types of assets, types of production profiles, the cash flow generating capacities and those are found throughout the continent of United States. So we're looking at properties and acquisitions that fit at which what we do, rather than stay within certain geographic areas.


Moving on to, John Ragozzino with RBC Capital Markets.

John Ragozzino - RBC Capital Markets

Can you just give us a little bit more color on the CapEx spent? You gave an indication that a lot of that stuff is going to be spent in the legacy California properties. Just given the timing of putting that capital to work, can you give us a feel for like the organic growth, you expect to see in the back half of the year from those properties, as well as how the acquired properties will shake out given that level of spending?

Mark Pease

We've actually had two pieces of capital increases. We announced earlier, that we're increasing about $19 million and that's primarily gone to our California oil properties. We have good results there, as I mentioned earlier on the prepared remarks. Then the rest of that, again, legacy of properties of the additional $50 million, about $20 million will go to those legacy properties.

So as we look at overall production drill for the company, we expect mid-teens growth Q3 compared to Q2 and then some additional growth on top of that. Again, part of that's due to an acquisitions closings, the part of it was due to the capital program with those acquisitions. Strong economics on these incremental dollars, and as I mentioned earlier there are essentially oil well. So that was the rational behind those.

John Ragozzino - RBC Capital Markets

And is there anything incremental, and this is either for Hal or Randy, anything you'll share with us that's incremental on the Collingswood. I think when we talked back in June, there was likely to be some additional well reserves available on the MDNR, and you also have not been able to dig them up yet. Anything that you could share with us there would be helpful?

Hal Washburn

Yes. There is really not a lot to share. We're constantly monitoring it, the reporting requirements in Michigan and what gets reported is, well it's not as much there, as you get in a lot of different states. So we don't know a lot more. We know that in Encana and Evan and others continue there development of both of the Utica Collingwood and the A-1 Carbonate, but nothing particularly new or noteworthy at this point.


Next is Jeff Robertson with Barclays.

Jeff Robertson - Barclays

Just a follow-up on the production question. Mark, can you talk about the trajectory of production as you exit 2012 and going to '13 with this incremental capital that you've planned to spend? And if we think about 2013 capital, are you setting kind of a new base level or capital on the asset base with where the second half spending this year will turn out?

Mark Pease

Trajectory wise, Jeff, we expect the Q4 to be low single-digit increase over Q3. Again Q3, isn't that pretty big increase, but that's due to the acquisitions in Q4, that low single-digit increases due to the additional capital we're inflowing.

And as far as capital levels, we started off the year at $67 million which was down pretty substantially when you factor in the acquisitions that we did in 2011. If you just look on a per reserve basis, the $67 million was lower than what we've done in 2011. But we've pulled a lot of gas projects out of there, redirected the teams, looking harder at oil projects. So our really mission in the first half of the year, has been to identify additional oil projects on our legacy assets.

So when we talk about 2013, I'd certainly expect this to be somewhere in the range of the revised capital program that we've given you. I mean, that's more consistent with our historic expand on a per barrel reserves basis, if you will.

Jeff Robertson - Barclays

And again, focused on primarily all on oil in '13, at least that you see that today, Mark?

Mark Pease

As we see it today, that's right, Jeff. And before we do anything on gas, we work those economics hard to make sure that they are competitive with what we're seeing on the whole side.


And moving on to Kevin Smith with Raymond James.

Kevin Smith - Raymond James

Would you mind elaborating on the interest provisions in the two California fields, and I guess specifically their impact on production this quarter?

Hal Washburn

Two California fields in the joint venture reach payout, at the beginning of April for the interest reverted. So with the productions, the interest drop from a approximately 95% or about two-thirds and definitely can't do that at top my head with the net production decrease was to 25.

Mark Pease

I've got a little bit of those numbers, Hal. Q2 was down about 1.7% compared to Q1, and we would have been down less than a 1.5%, we have had that interest reversion.

Hal Washburn

Mark had indicated me is that 300 barrels a day were down based on the reversion.

Kevin Smith - Raymond James

And then, I think you spoke little bit about this. You had you two shipments going out of Florida this month or this quarter?

Mark Pease

We did, one, first quarter and two, this quarter. We expect two per quarter, generally.

Kevin Smith - Raymond James

For some reason, I was thinking you might have three this quarter, just because you had a little bit of lag in Q1, but I guess that was incorrect?

Hal Washburn

We probably have about 100,000 net barrels in inventory at the end of the second quarter and we work that basically to try to work that down by the end of the year, but we don't also want to ship short loads because it just raises the cost of shipping per barrel.

Kevin Smith - Raymond James

And then, it's lastly for me, what hedging percentage are you comfortable with for 2013. I think the hedging percentage is, and correct me if I'm wrong, that you mentioned for oil side included current production, and then obviously with the acquisition coming in third quarter, that's going to lower it. Where do you want it to be, is the 74% the right range, after the acquisitions closing or cometh the three-fourth range, the right range before that transaction closes?

Jim Jackson

Remember that these percentages reflect as, hoping production flat which is what we expect that obviously we hedge, we continue to hedge in barrels as we spend capital on obviously in a lumpy fashion, as we do acquisitions. And the additional hedging other then for spending capital was really layered in kind of the years far out, 2015, 2016 and 2017, as the hedging that was associated with the acquisitions were resolved.

When we look at it from the banks perspective, we do have guidelines, what we're allowed to hedge. And then following that bank covenants or definitions, we feel most comfortable in the 88% type range. And if you look at our current production and expected PDP or PDMP rolling forward, that's basically where we are or slightly above that.

So we would look at the current portfolio other than, just wanting to add layer in some additional options which will provide for upside exposure, which would help us offset any spikes in oil prices, which get reflected in expenses and squeeze profit margins, and things of that nature. 80% is a good number for us. And we think, it definitely mitigates the volatility that we've experienced as you can see in our previous cash flows.

Kevin Smith - Raymond James

Well I guess the acquisitions is very closed, would you expect them to similarly close to that 70% to 80% on a go-forward basis, based on what's forecasted third quarter run rate is for 2013?

Jim Jackson



(Operator Instructions) And there are no further questions. Mr. Washburn, I'll turn the call back over to you for any 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. And operator, you may now bring this call to close.


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

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