BreitBurn Energy Partners' (BBEP) CEO Hal Washburn on Q1 2014 Results - Earnings Call Transcript

| About: Breitburn Energy (BBEPQ)

BreitBurn Energy Partners, L.P. (BBEP) Q1 2014 Earnings Conference Call May 8, 2014 1:00 PM ET


Greg Brown - EVP, General Counsel and CAO

Hal Washburn - CEO

Mark Pease - President and COO

Jim Jackson - CFO


Noel Parks - Ladenburg Thalmann

Praneeth Satish - Wells Fargo Securities


Please stand by. We’re about to begin. Ladies and gentlemen, thank you for standing-by. Welcome to the BreitBurn Energy Partners Investor Conference Call. BreitBurn’s press 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 today.

A replay of the call will be accessible until midnight Thursday, May 15th, by dialing 877-870-5176 and entering conference ID 1607316. 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, Executive Vice President, General Counsel, and Chief Administrative Officer of BreitBurn. Please go ahead sir.

Greg Brown

Thank you operator and good morning everyone. Participating with me this morning are Hal Washburn, BreitBurn's CEO; Mark Pease, BreitBurn's President and Chief Operating Officer; and Jim Jackson, BreitBurn’s Chief Financial Officer. After our formal remarks, we will open the call up for questions from securities analysts and institutional investors.

Let me remind you that today's conference call contains 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 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 contained in today’s earning’s press release and under the heading Risk Factors, which is incorporated by reference from our Annual Report on Form 10-K currently on file for the year ended December 31, 2013, and our quarterly reports on Form 10-Q, our current reports on Form 8-K and our other filings with the Securities and Exchange Commission. Except where legally required, the Partnership undertakes no obligation to update publicly any forward-looking statements to reflect new information or event.

Additionally, during the course of today's discussion, management will refer to adjusted EBITDA, and distributable cash flow which are non-GAAP financial measures and are reconciled to their most directly comparable GAAP measures in our earnings press release issued this morning. Management believes that these non-GAAP financial measures enhance comparability to prior period. Adjusted EBITDA is presented because 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.

Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-GAAP financial measures 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 or distributable cash flow in the same manner.

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

Hal Washburn

Thanks, Greg. Welcome everyone and thank you for joining us today to discuss our first quarter 2014 results. BreitBurn was off to a good start of what we expect to be another very active year. We have a significant capital program in $325 million and $345 million and anticipate spending virtually at 100% of our capital on oil projects across the company with the majority being focused on Texas, California and Oklahoma. We expect 85% of our total capital spending will be focused on drilling, rate generating and facility projects that are designed to increase production or add to our existing reserves. Our 2014 capital program includes drilling or re-drilling 168 gross wells in 5 states with 4 continuous drilling programs and up to 6 rigs running during the year. Our capital program is on track as we drilled 30 gross wells and completed 2 workovers during the first quarter. We currently have a total of 5 rigs running between Texas and California.

As you may know, given the size and time in our drilling projects and the typical winter weather challenges, activity in production scheduled to ramp-up during the remainder of the year. We remain on track to meet our 2014 production guidance of between 13.6 million and 14.1 million barrels of oil equivalent and our target of exceeding year with production ranging between 38,400 Boe per day and 40,800 Boe per day, 58% of which would be oil and 8% NGL.

Now, we briefly go over our first quarter highlight. Net production for the quarter was approximately 3.2 million Boe, which represents the 4% increase over the prior quarter. Liquids production came in at 2.1 million Boe, which represents a record quarter high for BreitBurn and comprised 64% of total production. Quarter-over-quarter we’re seeing our exposure to liquids increase our oil focused capital program. While our total production for the first quarter was slightly below our internal forecast mainly due to winter weather and unscheduled downtime in some of our properties, we’re pleased to report that our recently acquired Postle field and the Oklahoma Panhandle is responding to increase CO2 injection and is performing well. Additionally, while our Michigan team experienced extremely challenging operating conditions due to severe winter weather, they delivered great results with BreitBurn operative production coming in at forecast. Mark will discuss our operating results in further detail later in the call.

We’re also pleased to report record adjusted EBITDA of $117.8 million for the first quarter compared to $109.4 million in the fourth quarter of 2013.

We saw improvement in realized [ph] oil, NGL and natural gas prices across our properties compared to the previous quarter. In particular, we had the benefit of very attractive natural gas prices in Michigan while in Texas. Mark and Jim will provide more details on pricing later in the call.

As I mentioned earlier, our Oklahoma operations are going very well. We’re currently producing approximately 7,000 Boe per day. We saw favorable response from our wells due to additional CO2 that we secured under our recent amended contract with Exxon, and we also had very sumptuous workover program. In addition, controllable LOE or Least Operating Expenses for the quarter came in below our forecast.

Turning briefly to recent acquisitions, we took over the CrownQuest three operations on February 3, 2014 and our team is actively working on integrating the assets. Unfortunately, the wells were not performing quite as well as we’d expected at handover due to a couple of operational issues that Mark will discuss later. We expect the Texas production ramp-up throughout the year as these temporary issues are resolved and the capital program accelerates.

We’re pleased to have declared almost recent monthly distribution of $0.1658 or approximately $1.99 per unit on an annualized basis, which will be paid on May 14th. This represents a 4.7% increase from our first quarter 2013 distribution rate and marks our 16th consecutive quarterly distribution increase.

Our coverage ratio for the quarter was 1.0 time and with the expected ramp-up of our capital program, we’re expecting our coverage ratio to increase as we move to the year even before the benefit of any accretive acquisition.

On the acquisition front, we continue to be very active in discipline in pursuing new opportunities to grow our business. If you recall, last year was one of our most successful years in acquisition market. We exceeded our 2013 acquisition target of $500 million by completing approximately $1.2 billion in total transaction. This year, we’re targeting $600 million in acquisition. As I mentioned before in acquisition, our combination of acquisitions of that bus can truly move the needle for BreitBurn in terms of accretion to distributable cash flow and net asset value per unit. We’re confident in our ability to continue to excel in the acquisition’s bay. We’re currently seeing a broad range of deals in the market from various types of sellers including majors, large independent private owners and private equity back firm and that deal size is ranging from small to very large. We have ample financial flexibilities to fund acquisitions for the year and we’re always looking at ways to diversify our funding sources and Jim will discuss those details later.

Now, I’ll turn the call over to Mark, who will discuss operating results for the quarter.

Mark Pease

Thanks, Hal. We had good progress in our capital program with the completion of 30 gross, 27.8 net drilled wells and two workovers. We spent about $79 million in capital for the quarter that was essentially all focused on oil project.

Total net production for the first quarter was slightly below our forecast due to severe winter weather in Michigan, Wyoming and Texas while downtime in Florida and some base production underperformance in Texas, which I will discuss in detail later. Even with these issues, we delivered record high net liquids production for the quarter of 2.1 million barrels of oil equivalent, which was about 8% higher than the previous quarter and 71% higher than the first quarter of 2013. The increase was primarily the result of the significant acquisitions we closed in the second half of 2013 and the continued high level of development activity on our legacy oil assets.

As Hal mentioned earlier, first quarter production was within our expected range and with our active capital program this year, we expect a significant ramp-up in production throughout the year consistent with our exit rate guidance and we’re very confident with our full year production guidance.

Production mix for the quarter was about 56% oil, 8% NGLs and 36% natural gas. We’re pleased to see the strategy driving our capital programs and acquisitions continue to expand our exposure to oil.

Lease operating expenses and processing fees for the first quarter excluding production and property taxes were $20.81 per barrel of oil equivalent, which was slightly higher than the forecast and a little higher than last quarter’s expense of $20.56 per Boe. Costs were up due to the very difficult winter weather in our northern areas and in Texas and also due to increased well work in Florida. For the quarter, costs of raw materials and services decreased to about 5% due to our strategic sourcing throughout the supply chain. Some of the key areas of savings were freight services and direct proper purchases.

Now, let’s walk through some of the key operating areas. First, let’s discuss California where we were very busy. Production came in at 441,000 barrels of oil equivalent, which was up some compared to Q4 but slight behind the forecast mainly due to two issues. First, we had a shutdown at Sante Fe Springs to tie in a new electrical substation, which will deliver increased capacity to the field. This was necessary due to the ramp-up in production from our increased drilling activity. And we also had an oil pipeline set in at [indiscernible], which curtailed production for about a month.

Capital expenditures in California totaled $11.7 million for the quarter and included six new gross drill wells, which added incremental net initial production of about 725 barrels of oil equivalent per day and was above our forecast pre-year forecast. These six drill wells are all producers in the Sante Fe Springs 200th block. This is a new area inside the existing field but we completed leasing last year and the wells encountered excellent pressures and handle oil saturations.

Additionally, we acquired the remaining very small working interest in the Sante Fe Springs unit, which brings our total working interest to 100%. We also started drilling in our Belridge field during the quarter drilling a total of four wells. We plan to keep the rig drilling into the fourth quarter going at total of 48 wells. Belridge wells are completed in groups of eight. This improves our efficiency and reduces cost and we plan to start the first group of completions in mid June. We expect to spend about $48 million for the full year in California to drill 58 wells in the Belridge and Sante Fe Springs fields.

California controllable LOE was $33.68 per Boe for the quarter. This was lower than Q4 LOE of $34.45 but higher than forecast largely due to lower production for the reasons mentioned previously and due to our team undertaking and completing a significant amount of work at Sante Fe Springs taking advantage of the downtime while the fields were shut down for the electrical upgrade. In California crude oil differentials to brand improved to 95% compared to 90% in the fourth quarter. We continue to be pleased with the opportunities we develop in California and the associated results. So, we’ll remain a very active year for us in 2014.

Turning to our Texas operations. Net production for the quarter came in at 618,000 barrels of oil equivalent, which was below our forecast primarily due to downtime weather and the delay in trucking our oil volumes. When our team took over operations of the CrownQuest wells on February 3rd, there were number of wells that were off production. Due to activity levels in the Permian Basin it took some time to secure additional workover rigs to return those wells to production. Additionally, we had to build a long [side of oil] [ph] stock because of a shortage of crude oil, howling trucks in the area. Welling [ph] storage increased by approximately 11,000 barrels of oil equivalent this quarter and was not included in production or sales for the quarter and we expect it to be resolved by the end of the second quarter.

Capital expenditures in Texas totaled $53.2 million for the quarter and included the drilling and completion of 21 gross, 19.6 net new drill wells. During the first quarter, we ramped up to four operated rigs in Texas that are drilling about eight wells per month and we expect to operate those four rigs for most of the year. We have also been testing various lid systems to help accelerate cleanup of the completion first and improve the peak rate of the new drill wells. We have already seen success with the jet pumping installation and we will be testing electric submersible pumps and larger pumping units in the second quarter. We’re planning on spending about $165 million for the full year in Texas and will drill a total of 98 new wells. So, it’ll be a busy and exiting year for us there.

Controllable LOE for the quarter averaged $8.52 per Boe, which was down slightly from the $8.57 per BOE in Q4 and Texas continues to be our lowest cost operating area. Texas oil differentials were essentially flat with Q4 at 95% of WTI, which is wider than historic average. We are seeing some further widening in the differentials in the second quarter, but we expect this to improve as we go to the rest of the year. Current oil diffs are about 91% of WTI. NGL diffs improved for the quarter and were about 33% of WTI compared to 30% in 2013.

Now, let’s move to Oklahoma. Production for the quarter was 632,000 barrels of oil equivalent, which was above forecast mainly due to favorable production response from the additional CO2 that was delivered under the Exxon amendment beginning on January 1, 2014. If you recall, the delay in the Libby Ranch CO2 development project, which was operated by Whiting through completion significantly reduced CO2 supply and injection and ultimately oil production in the fourth quarter of 2013. The additional CO2 from Exxon along with the completion of the Libby Ranch project have positively impacted our operations and productions this quarter.

Capital activity for the quarter totaled about $9.3 million of which about $6.5 million was for CO2 purchases and the remainder was primarily associated with the 3D [indiscernible]. We’re planning to spend about $53 million for the full year in Oklahoma and that breaks down to approximately $31 million for CO2 purchases, $11.5 million for drilling CO2 supply wells at Libby Ranch, $8 million for developing new CO2 injection patterns and the remainder is for various projects.

Controllable LOE for the first quarter in Oklahoma came in at about $11.8 million or $19.04 per Boe, which was lower than forecast mainly due to lower well service cost. The group has had good success reducing the required number of workover rig days by utilizing oil tubing cleanouts.

Now, let’s shift to the northeast part of the unit, which is a smaller field southeast of Postle. As it benefited from the CO2 volumes coming from the amended Exxon contract we negotiated, started injecting CO2 there at the end of 2013, and by the end of the second quarter of this year we should be injecting into three wells continuously. So, we’re already starting to utilize CO2 in fields other than the Postle field. As we’ve stated a number of times, this is an excellent asset in our portfolio and we believe that owning a CO2 transportation infrastructure we’ll facilitate growing our business in the region.

Now, let’s move north to Wyoming. Production for the quarter was 600,000 barrels of oil equivalent, which was slightly below our forecast primarily due to difficult winter weather, which caused increased downtime. Recall that we typically experienced lower production in the first part of the year for our northern operations because of the winter weather condition. Drilling activity was relatively light as we planned. We completed two gross wells, one producer and one injector in the Greasewood field. For the full year, we expect to drill seven wells in Wyoming and spend total capital of $8 million. Controllable LOE for the quarter came in at $13.26 per Boe, which was slightly above forecast mainly due to higher propane purchases in the Greasewood field. And we had good news on the pricing in Wyoming. Crude oil differentials improved in the first quarter to 73% of WTI in Q4 and natural gas differentials improved from 100% to 105% of NYMEX quarter-over-quarter.

The last area one I want to touch on in Michigan, Indiana and Kentucky. As Hal mentioned, our team delivered good results despite very challenging weather condition. Production for the quarter was 797,000 barrels of oil equivalent, which was just slightly below our forecast. Last winter, Gaylord, Michigan which is in the center of our Michigan operations had the coldest winter on record. The average high temperature from December 1st to the end of February was 10.1 degrees Fahrenheit. This resulted in weather-related downtime that primarily affected our non-operated properties. Our field group did an excellent job this quarter to keep our wells and facilities running with minimal downtime, and these efforts were rewarded as we received some of the highest gas prices we’ve seen in several years in Michigan. Realized gas prices for the quarter was $7.50 per Mcf and got as high as $10.50 per Mcf in March. It was a very profitable quarter. A relief for the quarter was essentially right on forecast and came in at $12.79 per Boe. Also during the quarter we made working [indiscernible] interest acquisitions in Michigan, which totaled about $1.8 million and added approximately 500 Mcf per day of net production.

So, overall, Q1 was a busy quarter ramping up drilling activity in both the Permian Basin and the Belridge field in California integrating the new CrownQuest three acquisition, continuing to broaden our understanding of our CO2 assets in the Mid-Continent. We had five operated drilling rigs working at the end of Q1 and expect to increase the six operated rigs by midyear. With the increased activity in Texas and California, our capital program is balanced throughout the year and we expect to spend about three quarters of our 2014 capital budget in the last report of the year. With continued execution of our capital program, we’re on track to deliver 2014 production between 13.6 million and 14.4 million barrels of oil equivalent for the December 2014 exit rate between 38,400 and 40,800 barrels of oil equivalent per day. Providing we achieve the midpoint exit rate for 2014, it will be an increase of about 19% compared to the December 2013 average production rate. With the assets we’re on and the people BreitBurn has to manage them, we’re confident that our current capital program will meet expectations and deliver the guidance announced earlier this year. We’re excited about continuing a very active year.

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

Jim Jackson

Thank you, Mark. I will start by reviewing selected results for the first quarter and then provide an update about our hedging program and our liquidity position.

Adjusted EBITDA for the first quarter of 2014 was $117.8 million and a quarterly record high for the partnership. First quarter adjusted EBITDA increased 8% from $109.4 million during the prior quarter principally due to higher realized pricing oil, NGLs and gas, better oil and natural gas differentials in selected base and a bit of full quarter of production from the CrownQuest preacquisition, which closed at the end of 2013. Realized oil, NGL and natural gas prices excluding the effects of commodity derivative instruments averaged $92.12 per barrel, $42.89 per barrel and $6.51 per Mcf respectively in the first quarter of 2014 compared to $88.77 per barrel, $42.17 per barrel and $3.75 per Mcf respectively in the fourth quarter of 2013. During the quarter, we also saw better oil differentials in Florida and natural gas differentials in Wyoming, Oklahoma, Michigan, Indiana and Kentucky. Natural gas differentials in the Henry Hub in Michigan, Indiana and Kentucky in particular were about 40% better than forecast.

Turning to earnings, we recorded a net loss of approximately $9.8 million or $0.08 per diluted common unit as compared to a net loss of $58.8 million or $0.52 per diluted common unit in the fourth quarter of 2013, which also included the $54 million impairment charge in the fourth quarter of 2013.

Cash interest expense for the first quarter of 2014 was $28.6 million compared to $24.7 million for the fourth quarter of 2013.

Now I would like to discuss distributable cash flow. Distributable cash flow was approximately $60.3 million in the first quarter. This amount reflects adjusted EBITDA of approximately $117.8 million, less cash interest expense of $28.6 million, less in estimated amount for maintenance capital of approximately $29 million. We defined maintenance capital as the amount of annual investment required to keep production of approximately flat year-over-year. On a per unit basis, distributable cash flow in the first quarter was $0.496 per unit. As I mentioned, our coverage ratio for the quarter based on our current monthly distribution rate of $0.1658 per unit was 1.0 time. As a remainder, the first quarter of any given years typically are weakest quarter and our distribution coverage ratio due to production curtailment as a result of seasonal weather issues particularly in places like Wyoming and Michigan. As Mark mentioned, we also experienced some downtime and base product underperformance, but given the ramp-up in our capital program and higher liquids base production mix and the temporary nature of those other factors we expect our distribution coverage ratio to increase throughout the year.

Now, I would like to give you an update on our hedge book. We continue to see our hedging strategy play an integral role in mitigating commodity price volatility. As many of you know, we’re even seeing a prolonged backward dated crude oil curve. As an example, the BBI [ph] crew currently trades for about $100 per barrel today versus $92 per barrel for April of 2015 delivery and $86 per barrel for April 2016 delivery. As always, we plan to continue to aggressively hedge in the acquisitions that we made. With respect to existing production, we continue to closely monitor the future’s curve and opportunistically add hedges at attractive prices. We believe our hedge book provides significant protection against commodity price volatility over the next few years. For example, approximately 88% of our total estimated PDP production is hedged through 2016. We also intend to hedge the majority of production in the outer years once the future’s curve gets higher.

Assuming the midpoint of our 2014 production guidance just don’t flat, our production is hedged at 76% in 2014, 72% in 2015, 57% in 2016 and 30% in 2017. Average annual prices during this period will range between $82.20 and $93.69 per barrel for oil and $4.15 and $4.95 per MMBtu for gas.

An updated version of our commodity price protection portfolio presentation summarizing our hedges is available in the Events & Presentation section of the Investor Relations tab on our website.

Now, I would like to give an update on our financing activities and equity position. During the first quarter, we worked with our bank group to update our financial covenant package, which increases our financial flexibility. As you recall, our amended credit agreement eliminated the maximum total leverage and maximum senior secured leverage ratio requirements and add at a provision to maintain an interest coverage ratio no less than 2.5 times. As of today, our current interest coverage ratio is 4.27 times.

Also in last February, we successfully established an ATM program offering common units representing limited Partnership interest for aggregate proceeds of up to $200 million. We intend to use the net proceeds of any sales under the program for general corporate purposes, which may include among other things repayment of indebtedness [ph], acquisitions, capital expenditures in addition to the working capital.

During the first quarter, we issued less than 100,000 common units under the newly established program. With the combination of our ATM program, the revised credit facility covenant package and our ongoing efforts to diversity our funding sources, we believe we’re well positioned to finance the business without the pressing need for a traditional common equity issuance this year.

As for our liquidity position, our current outstanding debt balance is just under $2 billion and just the borrowings of $827 million under our credit facility and approximately $1.16 billion in outstanding senior note.

On April 25, 2014, we completed our spring 2014 burrowing base re-determination and we’re pleased to have increased our burrowing base from $1.5 billion to $1.6 billion with the likely commitments from the existing lenders of $1.4 billion. This brings our current total undrawn capacity on our credit facility to $573 million. As you can see, we have sufficient liquidity and enhanced financial flexibility to fund our operating plan for 2014.

Before I turn the call back over to Hal, I’d like to introduce all of you to Antonio D’Amico, one of the newest members of our management team. Antonio joins us a Vice President of Investor Relations and Government Affairs reporting jointly to me and our General Counsel, Greg Brown. He joins us after 18-year career in Occidental Petroleum and I look forward to introducing many view of Antonio in the weeks and months ahead. He’s based here in Los Angeles and will be supported by Jessica Tang in our Investor Relations group who many do know very well. With that, we’ve concluded our formal remarks. Operator, you may now open the call for questions.

Question-and-Answer Session


Thank you. (Operator Instructions) And are first question today will come from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Good afternoon or I guess good morning out there.

Hal Washburn

Good morning, Noel.

Noel Parks - Ladenburg Thalmann

Just a few things but first at Santa Fe Springs you’ve mentioned that the wells actually performed above forecast, so that is certainly positive. Talk a little bit about what it was to give us a sense that made them outperform instead it was done, you’re developing a different area.

Mark Pease

Yes. I can. This is Mark. There was an area inside the unit that was actually shut in back in the mid 80s when oil price was low and has never been reactivated. We started a very active program out there about 2.5 years ago and had a solid drilling program since very good results. And so that area basically hadn’t had any injection or production for 20 some years. So, we had a pretty active leasing program to go and tie up the leasing areas so we could go in and reactivate it. So, it’s an area which had been produced as much as the rest of the field has. So, we saw good pressures there and good oil saturations.

Noel Parks - Ladenburg Thalmann

Okay, great. And in the Permian, though I understand the weather issues and we’ve heard them across the industry, but the trouble we had is far as getting a hold of workover rigs and [indiscernible]crude service trucks. Do you think that was just kind of a result of dislocations of the weather or should effect those continue to be challenging heading in the rest of the year?

Mark Pease

Well. I think for the assets that we had operated we have a relatively good idea of what level of services we’ll need and re-plan and get commitments for those level of services. What caught us a little bit by surprise was when we took over the new group of wells from [indiscernible] in the year, there were more wells than what we typically have. So, that force us to see out and look for additional equipment in anytime to that in the Permian Basin because it’s so active, it’s difficult to find. So, it took us a little bit more time than it normally would. And then having said all that, we now got those wells in house and understand what they need, so, we’re planning for that going forward. So, we don’t think that’s going to be a long-term issue.

Noel Parks - Ladenburg Thalmann

In just those activities you saw intend [ph] out there, are you okay on the staffing’s front in the Permian both [indiscernible] and the field.

Mark Pease

We have a very good field organization out there. We’re fortunate to hire a very good production super attendant who knows the area very, very well. He came us recommended from some people we know well. So, that was a big key piece and we’ve built a good team here, technical team, sub specialist [ph] team here in the office in Houston. So, yeah, I think we’re in good shape.

Noel Parks - Ladenburg Thalmann

Great. That’s all for me.

Hal Washburn


Mark Pease

Thank you.


And next we move on to Praneeth Satish with Wells Fargo.

Praneeth Satish - Wells Fargo Securities

You mentioned that production at Postle is running at, I think, 7,000 barrels per day. How do you see that production ramp improving over the course of the year? I think originally when you acquired the properties, it was at 7,400.

Mark Pease

Yes, that’s right, Praneeth and this is Mark again. As we are getting more and more familiar with the reservoir out there and understanding the performance in a lot of the detail and also we’ve got a very good team working that. It looks like we’ve got a cycle time if you from when you change CO2 volumes to when you start seeing some response whether it’s up or down, and cycle time runs – and again it’s not exact of replacing the field, there is somewhere between six months and a year. And so we were having, production was declining as I mentioned during the fourth quarter of ’13, we got those additional CO2 volumes on the ground, we’ve already seen production levels off, it’s a good thing and so we expect that the some starting ramp up in production late this year.

Praneeth Satish - Wells Fargo Securities

And I guess it's been a few months since the Partnership has announced and acquisition. What's kept you out of the market so far? Has it been the wider bid/ask spreads, or just not the right type of assets on the market?

Hal Washburn

This is Hal. We have been in the market, we looked at a lot of transactions, the deal flow, get gross levels down slightly from last year we think but the number of deals that – we are looking for and the number that we fully evaluated is actually higher than what it was in the first quarter of 2013. We’re not just – we’re successful as you know we look at several hundred deals a year generally closed fewer than 10, and so far this year we have been successful bidder, we have looked at some properties that some of our peers acquired recently or in those processes, but obviously we are willing to pay with what they pay.


And there are no further questions at this time. I will turn the call back over to speakers for any additional or closing remarks.

Hal Washburn

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


Thank you. That will conclude today’s call. We thank you for your participation.

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