BreitBurn Energy Partners, L.P. Q2 2010 Earnings Call Transcript

| About: Breitburn Energy (BBEPQ)

BreitBurn Energy Partners, L.P. (BBEP) Q2 2010 Earnings Call August 4, 2010 1:00 PM ET


Greg Brown - EVP of Land, Legal and Government Affairs & General Counsel

Hal Washburn - CEO

Randy Breitenbach - President

Mark Pease - EVP & COO

Jim Jackson - EVP & CFO


Michael Blum - Wells Fargo

Richard Roy - Citigroup

David Newhouser - Livermore Partners

Chad Potter - RBC Capital Markets



Ladies and gentlemen, thank you for standing by. Welcome to the BreitBurn Energy Partners Investors Conference Call. The partnership’s news release made earlier today is available from its website at During the presentation, our 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 Thursday, August 4, 2010. A replay of the call will be accessible until midnight Thursday, August 18 by dialing 877-870-5176, and entering conference ID 9833247. International callers should dial 858-384-5517. An archive of this call will also be available on the BreitBurn website at

I would now like to turn the call over to Greg Brown, General Counsel of BreitBurn. Please go ahead, sir.

Greg Brown

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 for 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 which 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 press release and under the heading, risk factors incorporated by reference, from our annual report on Form 10-K for the year ended December 31, 2009, 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.

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 and 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.

With that introduction, 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 second quarter 2010 results. I am pleased to announce another very strong quarter for the partnership. With the consistent execution of our business strategy, we continue to meet or exceed 2010 guidance on all of our key metrics.

Let me start with a few of our key accomplishments. During the second quarter, we produced 1.663 million barrels of oil and natural gas or 18,270 Boe per day which trends towards the high end of our guidance ranges. These operating expenses, excluding transportation fees and property taxes came in below our guidance range of $17.82 per Boe, due to increased production, continued efforts by our team to reduce costs and normal variability and quarterly results.

We expect lease operating expenses will be consistent with guidance during the second half of the year. In early June, we announced initial production results of and an in-field development well in one of our selling on trend properties. The well was completed in early May at more than twice the expected production used in economics and produced approximately 1,100 barrels of oil per day during June. This increased production contributed to a higher than forecast second quarter adjusted EBITDA of $56.7 million, which is above our guidance range. We started drilling a second horizontal well in Raccoon Point in May, and expect initial results within the next 60 days.

On July 29, we held our first annual meeting of limited partners here in Los Angeles. All proposals were passed and I’m very pleased to announce though in the same day, our board of directors announced an increased distribution for the second quarter, which we announced on July 30. The new distribution of $0.3825 per unit, or $1.53 per unit on an annualized basis, will be paid on August 13, 2010 to the record holders of common units of the close of business on August 9, 2010.

Based on $1.53 distribution run-rate and our public guidance for 2010 distributable cash flow of approximately $120 million, which assumes maintenance capital expenditures of between $40 million and $50 million, our distribution coverage ratio is approximately 1.4 times. Our long-term coverage ratio remains approximately 1.2 times.

As such we will continue to consider additional quarterly distribution increases into next year based on our operating performance, the commodity price environment and other key factors as discussed in our public filings.

As we mentioned on our last call, in May we completed the syndication of amended credit facility with a borrowing base of $735 million. Given June 30, 2010 debt levels of $534 million, we have just over $200 million in borrowing capacity. With our improved liquidity position, we’ve become more active in reviewing potential acquisition opportunities.

However, given the strength of our distribution coverage ratio and our excellent hedge position, we do not need to complete and acquisition in 2010 and into 2011 to deliver on our stated goals and to support our distribution policy. As such, we will approach the acquisition market very selectively.

I’m pleased to report that after a more extensive review of our holdings in the Collingwood-Utica shale in Michigan, we are making a significant upward revision of our approximate net acreage position there as it relates to the deep rights.

As evidenced by our successes in the first half of the year, the partnership is delivering on its stated operational and financial goals. We have some excellent operational opportunities. Mark will provide forward the Michigan update shortly, and we look forward to the second half of 2010.

With that, I’ll turn the call over to Randy, who’ll cover additional highlights, discuss selective results for the quarter in the year, and recap our hedge portfolio. Randy?

Randy Breitenbach

Thank you, Hal, and welcome, everyone. I’d like to start by providing an update on the ownership levels of our largest unit holder Quicksilver Resources. On May 11, Quicksilver announced the transaction with Marshall R. Young Oil Company in which Quicksilver partially paid for an acquisition of assets for Marshall R. Young with 3.6 million of BBEP units. This innovative structure reduced Quicksilver’s ownership in the partnership from 21.3 million units or 40% to 17.7 million units or 33%.

During the period from June 7 to July 30, the Marshall R. Young Oil Company sold approximately 1.7 million of their units. We’re very pleased that our unit price performed well despite Marshall R. Young’s active selling program during this period.

Now switching topics. Let me move on to some details of our commodity hedging activity and the impact of these derivative instruments on our second quarter 2010 results. For the second quarter of 2010, crude oil and natural gas sales, including realized gains on commodity derivative instruments totaled $100.5 million, up from $92.6 million in the first quarter of this year.

Realized gains on commodity derivative instruments for the second quarter of 2010 and the first quarter contributed $18.4 million and $12.1 million respectively to the sales total, which highlights the impact of our strong hedged portfolio. Our realized oil and gas prices continue to compare favorably to WTI crude oil and NYMEX natural gas prices for the same period.

For the second quarter, our realized natural gas prices averaged $7.70 per Mcf and our realized crude oil liquids prices averaged $69.99 per barrel. We recorded non-cash unrealized gains from commodity derivative instruments for the second quarter of $33.2 million compared to non-cash unrealized gains in the first quarter of $39.9 million.

In April, we added 465,000 barrels of new oil hedges relating to 2011 and 2014 production at weighted average hedge prices of $88.86 and $91.75 respectively. We mentioned these additions on our May earnings conference call as well. No other oil or gas hedges were added during the second quarter.

We will continue to evaluate opportunities to layer in new hedges throughout the second half of 2010 as hedging our production is a very important part of our overall business strategy. Because we have not recently added any new hedges, we will not be providing a new hedge presentation on our website today. So please refer to the past investor presentations.

I’ll briefly summarize our current hedge positions for reference. Assuming the midpoint of 2010 production guidance has held flat. Our production is hedged at 84% in 2010, 81% in 2011, 70% in 2012, 56% in 2013 and 10% in 2014. Average annual prices during this period ranged between $79.02 and $90.42 per barrel of oil and $6.92 and $8.26 per MMBtu for gas.

Our hedging philosophy is one of the key strengths of the partnership and it has proven successful in mitigating commodity price volatility, stabilizing revenues and cash flows and supporting our borrowing base in the past. Despite volatile commodity prices over the past two years or so, we have managed to maintain generally stable EBITDA levels. A significant portion of our oil and gas volumes are well protected at attractive prices throughout the next four years, which puts us in a very strong position going forward.

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

Mark Pease

Thanks Randy. We had a very successful quarter from an operational perspective. I’ll run through results at the partnership level and then discuss some of the details by division.

Let me start by saying that our operations teams in both divisions continue to deliver very good results. During the second quarter we produced 1.663 million barrels of oil equivalent which equates to 18,270 barrels of oil equivalent per day. This is a 3% increase compared to the prior quarters’ production of 17,725 barrels of oil equivalent per and our production continues to trend towards the top end of our 2010 guidance range.

The production split for the quarter was approximately 51% natural gas and 49% crude oil and NGLs. Leased operating expenses and processing fees, excluding transportation expenses and property taxes came in at $29.6 million or $17.82 per barrel of oil equivalent for the second quarter of 2010, which is quite a bit lower on a per Boe basis than the $19.12 per barrel we incurred during the first quarter of this year.

The lower [loe] per barrel is due to several reasons, which I’ll touch on when I discuss each region. Overall the costs of services have remained relatively flat, but there continues to be slight upward pressure on the cost of materials, with these costs increasing approximately 5% to 10% over the last quarter.

Total capital expenditures in the second were $20.9 million. On an annualized basis, this is above our guidance of $72 million to $78 million, but it is consistent with our 2010 capital spending program in which the bulk of our program is executed in the second and third quarters.

Year-to-date we spend about $29 million and expect to spend toward the high end of our guidance range for the year. Both of our divisions performed very well this quarter with notable results in both Florida which is part of the Western division and Michigan, which is part of our Eastern division.

Let me first provide you with details for the Western division. Production in the Western division, which includes California, Wyoming and Florida was above forecast primarily due to the higher than forecast initial production rate of our new tracking point well in Florida.

We announced in our press release on June 8 that the 27-5AH our first horizontal well in the Sunniland Trend came in at more than double the pre-drill forecast production rate.

For the month of June, the well averaged approximately 1100 barrels of oil per day gross and 900 barrels of oil per day net to the partnership. Our second well was spud in May and planned for completion in July. However, during drilling, a portion of the drill string was stuck in the hole which required a side track. The side track has now been completed and we expect initial production results sometime within the next 60 days.

In addition to drilling our two Florida wells, capital program for the Western division during the second quarter involved drilling and completing four wells in Wyoming that came in essentially at forecast. Controllable lease operating expense per barrel was lower than forecast in Western due in part to higher produced volumes and lower than forecast well repair costs in California. This is partially offset by higher than normal well pulling costs in some of the other areas.

Now let’s move to the Eastern division, which includes Indiana, Kentucky and Michigan. Production was above forecast due primarily to better than forecast performance of three of our new [production] completions and also due to continued operational efficiencies.

Controllable lease operating expense per barrel in the Eastern division was lower than forecast due mainly to higher produced volumes, the timing of expected compressor repairs and maintenance and to a more mild than normal winter season. On the capital side, we ramped up activities significantly this quarter and completed eight drill wells, six well workovers and one facility optimization project.

Overall, we added incremental net production of 5.9 million cubic feet per day with our capital projects, which is more than double our pre-work forecast, with our two most successful projects each producing about 2.4 million cubic feet per day. We continue to evaluate the Collingwood-Utica Shale play in Michigan and the possible opportunities it may bring for the partnership.

As I mentioned last quarter, we have more than 470,000 net acres and significant midstream assets across northern Michigan. After an extensive analysis by our Michigan land team of our deep rides, it was determined that we hold more than 120,000 net acres in what we now consider the prospective area, up from the 90,000 net acres previously estimated and the vast majority of our deep rides are held by production.

We are well positioned to be a leading participant in the Collingwood Utica should it develop into a meaningful play, and we are evaluating a number of options on how best to proceed. So all in all, it was a very good quarter, with both divisions beating expectations on essentially all their operational metrics, and we now have what looks to be a very significant position in an exciting emerging play in Michigan.

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

Jim Jackson

Thank you, Mark. I’ll give some additional detail on our financial results and comment on our improved liquidity position. Oil and natural gas revenue, including realized gains and losses on commodity derivative instruments rose in the second quarter to $105.5 million compared to $92.6 million in the first quarter of the year. Realized gains on commodity derivative instruments were $18.4 million, a $6.3 million increased over the prior quarter.

Oil and NGL sales were impacted by higher average crude oil prices and higher sales volumes related to the increased production from our recently completed well in Florida. The second quarter adjusted EBITDA was $56.7 million, up from $51.1 million in the first quarter and trending above the high-end of our 2010 annual EBITDA guidance range of $190 million to $200 million primarily due to better than the forecast sales volumes, higher realized prices and lower total operating costs.

General and administrative expenses excluding non-cash unit based compensation expense for the second quarter were $5 million or $3.01 per Boe versus $6.4 million or $4 per Boe in the first quarter of 2010.

Second quarter G&A expenses annualized are below the low end of our guidance range, which can be largely attributed to lower than expected third-party legal and contract labor expenses, lower than expected new employee additions, and the timing of outside audit costs, the bulk of which were incurred in the first quarter. Of course, we will continue to aggressively manage our G&A costs; but as we ramp up activity and more actively review acquisition opportunities in the latter half of the year, we would expect G&A per Boe to trend towards our full-year midpoint guidance of $4 per Boe.

Production and property taxes totaled $4.2 million in the second quarter as compared to $5.6 million in the first quarter of 2010. During this quarter, we did benefit from refunds received on assessment revaluations for the years 2003 through 2006 in the Eastern region.

Net interest and other financing costs excluding realized and unrealized gains and losses on interest rate swaps for the second quarter were $5 million compared to $3.6 million in the first quarter of the year.

Cash interest expense, which includes realized gains and losses on interest rate swaps, but excludes debt amortization expense and unrealized gains and losses on interest rate swaps, totaled $6.9 million in the second quarter of 2010 versus $5.7 million in the first quarter of the year primarily reflecting the impact of higher all-in interest costs associated with our amended bank credit facility.

We recorded net income of $53.6 million or $0.94 per limited partnership unit for the second quarter versus $57.9 million or $1.02 per unit for the first quarter of 2010. Unrealized gains on commodity derivative instruments were $33.2 million in the second quarter of this year and $39.9 million in the first quarter.

Now let me turn to our liquidity position. Our outstanding borrowings as of June 30 were $534 million as compared to $523 millions as of March 31. As we mentioned, we completed the syndication of the partnerships amended bank credit facility with our group of lenders in May. This facility includes 15 banks as a borrowing base of $735 million and includes a number of important provisions giving us additional financial flexibility as compared to our prior facility.

As Hal mentioned, with this borrowing base level, we have just over $200 million in borrowing capacity. Our next borrowing base of redetermination is scheduled for October of this year.

Borrowings increased slightly during the quarter. The second quarter included, as Mark mentioned, a significant increase in client capital spending as well as our first quarter aggregate distribution payment of approximately $21 million. We also funded the $13 million payment related to the Quicksilver settlement and the fees and expenses relating to the completion of our amended credit facility during the period.

With respect to the Quicksilver settlement payments, we were reimbursed approximately $3 million in June, and continue to expect the remainder to be reimbursed by our insurers.

Based on our current guidance, we would expect debt levels to remain approximately even with second ending debt levels throughout the end of year. This expectation is consistent with, as Hal mentioned our long-term distribution coverage ratio targets of 1.2 times.

The first half of 2010 has been an excellent, both operationally and financially for the partnership. While the first quarter was significant in that we were able to solve the Quicksilver litigation and reinstate distributions, this quarter highlights a strong operating and financial performance, which results from our focus on our core business strategy. We look forward to paying our increased distribution of $38.25 to our valued unit holders on August 13.

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

Question-and-Answer session


Thank you very much. (Operator Instructions) We’ll first take Michael Blum with Wells Fargo.

Michael Blum - Wells Fargo

A couple of quick questions. One, do you have any updated thoughts or insights into Quicksilver’s remaining rights bringing to the hold. Obviously they’re selling out of the MLP structure as a whole, obviously, just curious if you had any new insights into that?

Hal Washburn

Michael, we have an ongoing dialogue with Quicksilver, and really I think their interest in BreitBurn hasn’t changed. I think they would use the units opportunistically as they did in the Marshall R. Young transaction. But I don’t see them selling the units in the markets today, just generally selling into the markets. But again, we are talking to them, and that situation is really kind of in there, that’s their decision, not the partnership’s.

Michael Blum - Wells Fargo

Okay. And then on the Collingwood acreage, can you maybe flesh out a bit kind of what options are strategic alternatives you think about for that acreage? Obviously it has significant value, and maybe not within an MLP structure; but clearly a lot of value?

Mark Pease

Sure, Michael. There are a whole host of options that we have, including JVs, like JVs that are done in the shale plays and outright sale of the acreage, sale across the acreage, drilling carries.

We’re looking really at all of the different models and different options that are out there. There’s a whole number of transactions that have begun in the Marcellus, the Barnett, the Hayneville and all the other big shale plays, and we’re very familiar with those structures, and we’re looking at all of them. And we’ll determine what’s the best for the partnership as we go forward, and it will probably be in all likelihood, a combination of several different options given our very large acreage position.

Michael Blum - Wells Fargo

Okay. And then my final question is just, can you provide a little more commentary on what you are seeing in the A&D market? Kind of where valuations are right now? What looks attractive to you, oil versus gas there?

Hal Washburn

Michael, we’re looking at everything that’s on the market. All the deals that have been announced we’ve seen; and there are strong evaluations for oil properties today. We think the gas is probably somewhat undervalued, dependent on what your belief is long-term on gas prices. The market is not as active as it has been at other times. We expect to see more conventional assets come on the market as companies look to fund their unconventional resource development.

So we’re cautiously optimistic that we’ll see a lot of good properties. But as we said, we’re not forced to make acquisitions this year, really even in to next year, to execute on our strategy.


We’ll now move on to Richard Roy with Citi.

Richard Roy - Citigroup

Thank you. Michael asked most of my questions. But just one more it went to the distribution. So as you’ve been stating in February, I mean, the coverage ratio was always strong, and the recent increase, does that reflect a change in queue based on more comfort with the environment or your assets, or is that what you envisioned early on is that you would move towards your 1.2 long-term coverage ratio?

Mark Pease

Richard, we said pretty consistently, well, we think this business runs very well at about a 1.2, as our target. We could stomach a higher distribution coverage ratio for periods of time as well as lower, but we think 1.2 is a good long-term target. We look to be moving toward that over the course of the next few quarters this year into next year.

A lot of that depends on our continued good operating performance, continued strength in commodity prices, financial markets holding together; but, we will move toward that coverage ratio long-term, and this is very consistent, just move from 150 to 153 is very consistent with that goal.

Jim Jackson

Richard, its Jim. The only other thing I would add there is, when we reinstated distributions at the level we did, we were cognizant of the fact that, that coverage ratio, when you look at our public guidance for the year was going to be well north of 1.2. But, we obviously were coming out of an uncertain period. We have a lot more visibility on the business now. So, as we go forward, as Hal mentioned, we’ll continue to evaluate things, and work towards the 1.2 level.


(Operator Instructions) We’ll now move on to David Newhouser with Livermore Partners.

David Newhouser - Livermore Partners

Randy, you had another solid quarter, so it’s really hard to follow-up with questions after the consistency that we’ve seen after obviously last year; but again, I’ll touch on the M&A side whereas are you more focused right now, as you were saying on the conventional side; and if so, are you looking to focus more on oil and gas? And if you can just add some more color on to that?

Randy Breitenbach

Yes. We’ve been pretty clear in saying that our focus is on conventional assets, long life oil and gas reserves. The unconventional assets at least early on don’t fit the MLP model particularly well. They require a tremendous amount of capital, in most cases far outstripping their cash flow generating capacity, and they go on very high decline. In the future, as these unconventional assets mature, we do believe they’ll fit the MLP model. But today there aren’t a lot of material unconventional assets so our focus in the M&A arena is on conventional assets, long life oil and gas reserves consistent with the type of assets that are in the partnership today.

As far as a bias toward oil and gas, you know, as I said, we continue to believe gas is somewhat undervalued compared to oil. But we are looking at properties that have both oil and gas production.

We’re not looking to skew dramatically on the way from where we are today, which is very close to 50-50 gas and oil. We will make acquisitions that are a 100% one or the other, but we’re not focusing to raise one or the other. And again, we don’t need to do a deal. I think that’s a very important point. We don’t need to do a deal this year and really into next year to be able to execute on our strategy and to have a successful year.

David Newhouser - Livermore Partners

Okay. And as far as geography, if you were looking, are there any areas particularly as far as geography that you would focus on more, east or west? And then to fund and acquisition, what kind of flexibility would you look at? Would you fund it more with the excess cash on the following base? Would you use the MLP, or what’s your thoughts there?

Randy Breitenbach

Sure. Let me talk about the types of acquisition and let Jim talk about financing. You know, we value the geographic diversity that we have today. It allows us the option to look at a lot of different acquisition opportunities. We would look very hard at built on the opportunities near the basins and the areas that we currently operate i.e. California, the Rockies, Michigan. So, we would look hard at built on opportunities but we’re not geographically focused, we really focused on or constrained, I guess is a better way to put it. We are geographically constrained, but focused on the types of properties that fit our model. Large accumulation of oil and gas, well decline, the potential to apply our operating, engineering and other technical expertise to increase reserves, increase production and increase cash flow. So we’re not burdened by being in any one geographic area. We can look in lot of areas and we’re not burdened by having just one commodity. As far as financing, Jim, why don’t you take that one?

Jim Jackson

Sure. We have much more financial flexibility today than we had even six months ago or a year ago. So I think we’ll be opportunistic about how we finance things. David, that being said, we’re very consistent in that our view of what the capital structure should look like long-term is, well remains the same. We’re really not interested in running the business on an ongoing basis at north of 2.5 times coverage. But along the way, we’re also going to make sure we finance any acquisitions as efficiently as possible.

David Newhouser - Livermore Partners

Okay. And as far as the Michigan play, is there any timetable given on as which route you’re focused on as far as a JBS of some sort? Is there a time frame you’re looking to make and announcement by?

Randy Breitenbach

No, there’s really not. We’re in the enviable position of having virtually all of our acreage held by production. That means we don’t have lease expirations. We don’t have any drilling commitments. We’re really in a position where we can sit and watch the play develop and evaluate when we think the right time is to do a transaction. As I said earlier, the odds are we do a series of transactions or several transactions. We have such a large acreage position that we’re not likely to do just one very, very large transaction. Possible, but it’s probably not the way we would go. So, we’ll watch the play develop. We’ll watch the play develop, we’ll watch other operators, and we’re continually in discussions with people, other operator’s financial sources, potential JV partners and we continue those discussions and move forward when we think its right.

David Newhouser - Livermore Partners

And I’ll ask my last question, which is more macro, and I won’t ask you for a forecast, Hal. What are your thoughts where we are at right now with the commodity cycle here? Are we going to be stable do you think going into the next year or two? Or will a weakened demand or possible downturn cause commodity prices to see further weakness at some point? I mean right now they’re solid now.

Hal Washburn

I’ve taken all the easy questions. So I’m going to pump this over to my partner, Randy.

Randy Breitenbach

I would say that that is the reason we hedge. Given that there has been so much volatility, and I would argue there is no way of calling the market, especially in the short-term. What we do believe, and it’s a long-term belief is that the value and the price, or value of the commodity should reflect its energy content, and right now there is such a large dislocation in value, that overtime that will tend to work it way out of the system. That is really the only call we try to make. And I would say that we’ve been through several cycles, and each cycle seems to end for a different reason, and there are so many different factors that affect all of the above that, I mean, it is the sole reason that we hedge, and we hedge as extensively and as far out as we can so that we have visibility.


(Operator Instructions). We’ll now go to Chad Potter with RBC Capital Markets.

Chad Potter - RBC Capital Markets

Good morning. Just had a couple of questions on the Raccoon Point well, can you guys tell us what that well costs to drill and complete?

Hal Washburn

The initial well cost right at $9 million and the second one is going to be little bit more than that, because we had to do a side track.

Chad Potter - RBC Capital Markets

Right. How much do you think that adds? A couple hundred thousand dollars more?

Hal Washburn

No. It will be a little over 10.

Chad Potter - RBC Capital Markets

Okay. And do you guys have any EUR on those wells at this point?

Hal Washburn

Yeah. But we haven’t released the reserves publicly, and we don’t typically do that on a well by well basis, but it’s very economic let me put it that way.

Chad Potter - RBC Capital Markets

Yes. How long of a well life would you think I’m already trying to run a model on it?

Hal Washburn

They are hyperbolic declines. And so we’ve got, you know, the existing wells in the field have been produced and 20 plus years. So I think that’s indicative. I mean it’s a reasonably strong water drive. So, water comes up as well produces, the well stabilizes, and you have a very, very shallow terminal decline.

Chad Potter - RBC Capital Markets

Okay. Okay. And I guess the last question on that is just the repeatability, how many more locations do you think you have that you could drill and the horizontal, since your well design?

Hal Washburn

Well I mean that’s one of the things that really exciting about it. We’re looking at that right now. As we mentioned and everything we said, this was our first well, but to give you a little bit more color on, it was a horizontal well and an area of the field, it was and in-field well that had mainly been developed with vertical wells. So we think we’re increasing our efficiency. The second, what we’re drilling is essentially the time, and then we’re evaluating are there some potential step-out locations where we can extend boundaries of fields. So we think there are a couple of areas where we can find additional locations, and I do want to qualify that we haven’t found those yet, but we’re looking at them. And then I’ll also say, we’ve got other fields out there besides the Raccoon Point field, a couple of which are big fields that were primarily developed with vertical wells. So if we can prove success here, we may be able to take some of the others filed as well.


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

Hal Washburn

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


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

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