Ladies and gentlemen, thank you for standing by. Welcome to the BreitBurn Energy Partners' Investor Conference Call. The partnership's news release made earlier today is available from its website at www.breitburn.com. 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 August 6, 2013. A replay of this call will be accessible until midnight Tuesday, August 13, by dialing (877)-870-5176 and entering conference ID 5936311. International callers should dial (858)-385-5517. An archive of this call will also be made available on the BreitBurn website at www.breitburn.com.
I would now like to turn the call over to Greg Brown, BreitBurn’s Executive Vice President, General Counsel, and Chief Administrative Officer. Please go ahead sir.
Thank you, and good morning to all. Participating with me this morning are Hal Washburn, BreitBurn's CEO; and 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 for questions from securities analysts and institutional investors.
Let me just 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 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 is set forth in the cautionary statement relative to forward-looking information section of today's release and under the heading Risk Factors incorporated by reference from our Annual Report on Form 10-K currently on file for the year ended December 31, 2012, 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.
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 alternative 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 call over to Hal.
Thanks, Greg. Welcome, everyone, and thank you for joining us today to discuss our second quarter 2013 results. We delivered solid quarter with record quarterly high production, profitability levels at the high end of our guidance range and the announcement and early close of a significant acquisition.
In the second quarter of 2013 we produced 2.45 million Boe, of oil and natural gas which was a record quarterly high for the partnership due to the ramp up of a very active capital program that is currently delivering results above our expectations.
Second quarter production increased 5% from the first quarter of 2013, and 26% from the second quarter of 2012. As we entered the second half of the year we are right on track with our capital program and expect to meet our updated second half 2013 guidance, which was issued on June 24, 2013 in conjunction with the announcement of the Oklahoma Panhandle Asset acquisition. Mark will discuss the details on our operations in progress with the capital program later on in this call.
Our profitability in the second quarter was also above our guidance range. Adjusted EBITDA for the quarter was $84.8 million, which represented a 32% increase from the prior quarter and a 31% increase from the second quarter of 2012.
This quarter we had higher crude oil and natural gas sales volumes and higher average realized prices. We also saw better differentials in Wyoming, Texas and Michigan as compared to last quarter, where lower realizations weighed significantly on our adjusted EBITDA.
Now I would like to give an update on our acquisition activity for the quarter. As you know, on June 24th we signed a definitive agreement with Whiting Oil and Gas Corporation to acquire their interest in Postle and Northeast Hardesty oil fields located primarily in the Oklahoma Panhandle along with associated mid-stream assets.
The deal also included the acquisition of additional interest in the acquired assets from other sellers. We will refer to this acquisition hereafter as the Postle acquisition. We had an initial expected close date of July 30th but our team worked effectively to get the deal closed early on July 15th for $876 million.
The second quarter numbers that we’re presenting today do not reflect any benefit of the Postle acquisition. We are extremely proud of all the hard work and dedication our team has put in for the successful completion of a large and intricate deal.
There are so many great attributes about the Postle acquisition and I just want to highlight some of the ways that it impacts our business. First the Postle assets are excellent MLP assets with shallow decline and low maintenance capital requirements. This makes the transaction substantially accretive to distributable cash flow in a near end long term.
Second, we expanded our geographic diversity by gaining new operations in Oklahoma and mid-stream assets in New Mexico and Texas. The Whiting team has done an excellent job developing these assets and we expect to build upon the work that they have done. This enhances our growth platform as we see many expansion opportunities in the mid-continent and the Permian.
The Postle acquisition works to immediately add scale to our portfolio by increasing our average daily production by approximately 28%. The significant increase in scale immediately enhances our bottomline and distributable cash flow.
Finally the Postle deal further increases our focus on oil. Oil now comprises 57% of total production and liquids including NGLs comprised 64% of total production. This is a significant shift from our 2012 levels of 44% liquids production.
We have steadily transformed the commodity mix in our portfolio through acquisitions of high quality oil assets such as Postle. During the same period we also expanded our PUD as a percentage of proved reserves from 9% to 22% providing additional organic growth opportunities in our portfolio.
All together, the benefits of the Postle acquisition work to support our ability to continue to grow distributions. The substantially accretive deal enhances our visibility on DCF coverage and distribution growth and we like what we are seeing so far.
For the second half of 2013, we expect our DCF coverage to expand to approximately 1.4 times before the impact of opportunistic financings. With the successes of our expanded capital program and our demonstrated ability to grow through acquisitions, we are looking forward to the balance of the year which we believe will be one of the strongest periods in the partnership's history.
With that I will turn to our distribution this quarter. We're pleased to announce our second quarter 2013 distribution of $0.48 per unit or $1.92 per unit on an annualized basis. This represents our 13th consecutive quarterly distribution increase.
Overall, we had an excellent second quarter. We continue to be very successful in deriving value for our legacy assets for the operating plan. We also continue to be very successful in growing our business. With this highly accretive $876 million deal, we significantly ceded our 2013 acquisition target of $500 million. We are strong operators and always been proud of our ability to consistently deliver on our stated goals as part of our responsibility to our investors.
Our performance in the first half of the year positions us for strong second half and we look forward to another great year. I want to thank the BreitBurn for their hard-work and dedication and our investors for their continued support.
With that I will turn the call over to Mark, who will discuss operating results for the quarter. Mark?
Thank you, Hal. The planned ramp up of our capital program, continued in the second quarter and delivered very good results. We completed 38 gross, 30.4 net drilled wells, and 21 workovers during the second quarter. This activity level is more than double that of the first quarter when we completed 16 gross drilled wells and 10 workovers and we expect to continue the increased activity level of the second quarter for the rest of the year.
Our capital program helped BreitBurn deliver record quarterly net production of 2.45 million Boe which represents 4.6% increase from the first quarter of 2013 and a 26% increase from the second quarter of 2012. We spent a total of about $67 million in capital and it was essentially all focused on oil projects. As a result, we increased liquids production by about 6.7% compared to the first quarter of 2013, and increase liquids production 58% compared to the second quarter of 2012.
Production mix for the quarter was about 52% oil and NGLs and 48% natural gas, compared to 51% oil and NGLs and 49% natural gas for the prior quarter. These operating expenses and processing fees for the second quarter excluding production and property taxes were $19.79 per Boe, slightly higher than last quarter’s $19.42 per Boe due to well work in West Texas, facility work in California and well failures in Florida due to lightning storms.
Overall, LOE for the second quarter is well within our guidance range. Excluding the possible acquisition, our first half 2013 operating results and our expectations for the full year are right in the middle of our original guidance range.
Now, I will walk through the different operating areas by state. Let’s go to California first. Operating results from our California fields were very good for the quarter. Production for the second quarter came in at 423,000 Boe, which is better than forecast and 12.5% higher than the prior quarter. Capital expenditures in California totaled $24.4 million for the quarter, and included 15 new 100% working interest drill wells and four workovers.
We continued our higher level of activity in the Santa Fe Springs Field this quarter and are pleased to see the performance of the new wells and workovers than the first and second quarters of the year coming above our expectations.
For the quarter, we drilled five wells, two producers and three injectors. We have had a rig running continuously in Santa Fe Springs since March of 2012 and expected to run through the rest of the year drilling a total of 26 wells in 2013. This year, we have also done significant work in the Santa Fe’s Springs Field to increase water handling, water injection and electric power capacities. Water handling capacity was increased from 125,000 barrels of water per day in December of 2012 to 170,000 barrels of water per day today.
We expect facility work to continue as we design and build the necessary infrastructure to support future production growth. We are also beginning our development drilling program in the Belridge field this quarter and it is looking very promising. During the quarter, we drilled 20, 100% working interest wells at Belridge and completed 10 of those. We have worked to optimize the completions at Belridge and while we do not have a lot of production history on the new wells, we are seeing a significant increase in the initial production rates compared to our pre-drill forecast. So far, we are very encouraged by the results.
We expect to spend a total of just over $40 million for the second half of 2013 in California. California controllable LOE was $15.2 million or $36.35 per Boe for the quarter. This was slightly higher than our first quarter controllable LOE of $34.37 per Boe largely due to the ongoing work at Santa Fe Springs.
California has been and continues to be a great asset for the partnership that provides growth opportunities at very economic rates. We have identified multiple undeveloped locations in the Santa Fe Springs and the Belridge fields that should result in drilling programs for the next few years. We are also very pleased to have acquired 25 net acres of minerals in the Santa Fe Springs Field that will provide at least 15 more locations. So as you can see, we expect to remain very active in California.
Turning to our Texas operations. Net production for the quarter came in at 355,000 Boe, which was slightly below our forecast but 7.3% higher than the prior quarter due to the new drill wells that are being brought on production.
Capital expenditures in Texas totaled $20.4 million for the quarter and included the drilling in completion of 14 gross, 10.5 net new drilled wells, compared to 9 gross 4.6 net new drilled wells in the first quarter. A reduced production compared to forecast reflects continued gas curtailment, most of which we believe will be resolved during the third quarter. We are working closely with the gathering and processing companies to maximize production and minimize curtailment.
We had four rigs running for most of second quarter and we picked up the first BreitBurn operated rig early in the third quarter. So we currently have five rigs running on our Texas properties. We expected around four to five rigs for the remainder of the year and by year-end all drilling operations will transition from CrownQuest to BreitBurn.
We are very pleased to have developed a strong working relationship with CrownQuest during the transition period, which not only helped facilitate our takeover of the producing operations but also greatly accelerated our running on the drilling and completions in West Texas.
We are planning on spending about $55 million in the second half of 2013 in Texas, compared to $40 million in the first half of year and expect to drill total of 60 gross, 38.7 net new wells in 2013. Controllable LOE for the quarter was approximately $3 million or $8.31 per Boe. This is up from the $7.61 per Boe in Q1 due to increased materials cost and increased well work on some nonrecurring projects. Because of this nonrecurring well work, we expect Q3 operating cost to come in below the Q2 cost. Texas continues to be our lowest cost operating area.
Now, let's move north to Wyoming. Production for the quarter was 653,000 barrels of oil equivalent which was above forecast and 5.5% higher than the prior quarter. The increase in production was mainly attributable to warmer weather conditions which decreased downtime and favorable water flood response of the Greasewood field in Eastern Wyoming.
Capital expenditures for the quarter were about $10.6 million, which included the eight drilled wells and eight workovers. Controllable LOE for the quarter was $7.5 million or %11.49 per Boe which was under forecast and lower than the $12.32 per Boe that we reported for the first quarter.
We started our first 2013 drill well in early May and we picked the second rig by the end of the second quarter. We expect to drill 12 gross wells in the second half of 2013 in Wyoming and spend total capital of about $27 million for the full year.
Moving on to Florida, production for the quarter was 159,000 Boe, which was below our forecast and represented an 8.7% decrease from the prior quarter. Essentially all of the decrease compared to the first quarter was attributable to barge delays that backed up production shipments to the Port Everglades storage facility. Fortunately the wells were not shut in as we had sufficient tank capacity at the well sites. So this production will be made in the third quarter.
Capital spending for the quarter was about $6 million and included a portion of one drill well, the Bear Island 2-12. Bear Island 3-7, which is an offset through the Bear Island 2-12 is currently drilling and we expect to complete it during the third quarter.
We plan to drill a total of three gross 100% working interest wells and spend total capital of about $30 million in the second half of 2013. Controllable LOE for the quarter was 23% above forecast due mainly to the reduced volumes related to the barge issue and also due to downtime caused by a large number of lightning storms.
The last area I would like to discuss is Michigan, Indiana and Kentucky. We had a very quarter with our operations there. Production for the quarter was 863,000 barrels of oil equivalent, which was above forecast and about 2% above our first quarter production of 847,000 Boe.
This is a result of better than forecast production in our new DRZ oil wells at Beaver Creek and in the existing Prairie du Chien wells. LOE for the quarter was about 15% below forecast due to lower well servicing activity and lower non-operated expenses. Capital expenditures in Michigan totaled about $3.8 million for the quarter and included nine recompletions.
As production in Michigan, Indiana, and Kentucky is mainly natural gas, capital expenditures for the second half of the year are expected to only be about $8 million and this capital will mainly be focused on work in the Detroit river oil zone.
I already discussed the Postle acquisition but I would like quickly talk about a couple of more of the key points. First of all these are more big complex fields that had very large amounts of original oil in place and have very large amounts of oils still remaining in the reservoirs. As such they are very good fit for a business model of working in large reservoirs that requires sophisticated tools and technology and detailed reservoir management.
The Whiting staff, both in the field and in office have done a very good work in understanding the reservoirs, implementing projects and managing these fields. This transfer of knowledge, technology, and capability will be very important at BreitBurn.
Second, having control of the CO2 transportation infrastructure will be important and value adding to the fields we purchased and we believe it will be a differentiating factor as we look for continued growth in the area. From an operations perspective, we are very excited about the specific assets we purchased and the presence we have now established in the area and it's an area that I personally now well as I lived in southwest Kansas and worked in southwest Kansas and Oklahoma Panhandle for nine years earlier in my career.
So in summary, the first half of the year was a very busy with second quarter activity ramping up significantly compared to the first quarter and we expect the second quarter activity level to continue during the second half of the year. Excluding the Postle acquisition, we expect to spend about $261 million to drill 135 gross 111.5 net wells that are essentially all oil projects on our legacy properties.
Again excluding Postle, production and costs from our legacy properties are essentially right in the middle of our guidance range for the year and we expect to gross liquids production on the legacy properties by over 35% from Q4 2012 to Q4 2013.
As outlined in our second half guidance with the Postle acquisition, we now expect our December 2013 exit rate to be between 34,700 and 36,100 Boe per day and oil and NGLs will make up about 64% of our production.
With that I'll turn the call over to Jim.
Thank you, Mark. I'd like to start by giving some additional commentary on our financial performance during the quarter, then provide an update on our hedging activity and conclude with a discussion of our strong liquidity position.
As Hal mentioned, adjusted EBITDA for the second quarter for the second quarter of 2013 was approximately $84.8 million compared to $64.1 million in the first quarter. The increase was primarily the result of higher crude oil and natural gas sales volumes, higher average realized prices, better differentials than Wyoming, Texas and Michigan and we also benefited from ongoing cost containment and lower G&A expenses during the quarter.
For the second quarter of 2013 gains on commodity derivative instruments were $67 million, compared to losses of $24.2 million in the prior quarter which primarily reflects a decrease in crude oil and natural gas futures prices during the second quarter of 2013, compared to an increase in crude oil and natural gas futures prices during the first quarter of 2013.
Derivative instruments settlements received were $4.8 million in the second quarter of 2013, compared to $5.2 million in the first quarter of 2013. Let me point out that these settlements exclude prepaid premiums paid in 2012, related to crude oil derivatives that settled during the three months ended June 30 2013, and March 31, 2013, of $1.2 million in each of those quarters.
As you may recall in conjunction with many of the acquisitions we made in 2012, we invested in options premiums as a small part of our overall hedging program. During 2012 we did a series of unique deals that we elected to hedge in a variety of ways, all of which was consistent with our goal of protecting acquisition economics and accretion to distributable cash flow. These investments totaled approximately $30 million in 2012 and were used to purchase a variety of oil and gas options, swaps and PUDs. The hedging contracts cover 2013 through 2017 expected production volumes in varying degrees.
Allocating our total investment over that five year production period, it works out to an average of about $6 million per year in assumed costs or approximately 1.25% of our annualized second half 2000 run rate adjusted EBITDA. So as you can these are a very small part of our overall hedging strategy and our overall portfolio.
We have not incurred prepaid option premiums in 2013 and did not incur prepaid premiums in any years prior to 2012. Regarding net earnings, we've recorded a net gain of approximately $76.4 million or $0.75 per diluted common unit, as compared to a net loss of $36.3 million or $0.38 per diluted common unit for the first quarter of 2013.
The increase was primarily due to higher gains on commodity derivative instruments as compared to the prior quarter. Cash interest expense for the second quarter of 2013 was $17.1 million, compared to $17.2 million in the first quarter of this year.
Now I'd like to discuss distributable cash flow for the quarter. Distributable cash flow was approximately $48.3 million in the second quarter. This amount reflects adjusted EBITDA of $84.8 million, less cash interest expense of $17.1 million, less than assumed amount for maintenance capital of approximately $19.5 million, and we define maintenance capital as that amount of annual investment required to keep production approximately flat year over year.
On a per unit basis distributable cash flow was approximately $0.48 per unit. Our coverage ratio for the quarter based on the $0.48 distribution to be paid on August 14th was one times and it was a significant improvement from our first quarter coverage ratio of 0.67 times.
This improvement reflects the continued ramp up in our production profile and sales volumes before any acquisitions as planned throughout the year, an increased focus on liquids production during the year, settling (ph) oil and gas differentials across much of the portfolio and lower G&A expenses.
Given the planned ramp up in our legacy asset capital program and now with a benefit of the recent Postle acquisition, we expect our distribution coverage ratio to increase steadily throughout the second half of the year to approximately 1.4 to 1.5 times in the fourth quarter, absent any opportunistic financings.
As we said in our first quarter earnings call, even before the Postle acquisition materialized, given the anticipated ramp up of our legacy asset capital program and the changing production mix with an emphasis towards oil, we expected our distribution coverage ratio to increase steadily throughout the year to our target range of 1.1 to 1.2 times in the fourth quarter. Again, that was before the impact of the Postle transaction. So the Postle acquisition is an excellent addition and further enhances our distributable cash flow per unit profile.
Let me now turn to realized prices. Realized natural gas prices for the quarter excluding the effects of commodity derivative instruments averaged $4.22 per mcf, compared to Henry Hub natural gas top prices of $4.02 per mcf. On the oil side average realized crude oil and liquids prices excluding the effects of commodity derivative instruments were $87.82 per barrel, compared to Nymex crude oil spot prices of approximately $94.05 per barrel.
Brent crude oil spot prices, which are an important benchmark for California oil production averaged a $102.57 per barrel in the second quarter of 2013, compared to a $112.47 in the first quarter of 2013.
Now let me touch on hedging. Consistent with our hedging strategy, we continued to systematically expand our hedge portfolio and hedge acquisitions very aggressively since we talked last. During the second quarter we added approximately 2.1 million Boe of crude oil and gas hedges for the period covering the third quarter of 2013 through 2017.
In addition, as part of the Postle acquisition, we added significantly more oil hedges to the portfolio. In fact, we added 5.4 million barrels of oil for the period covering the third quarter of 2013 to the first quarter of 2016 at $95.44 per barrel on average as part of the transaction.
More recently, however, following the close of the Postle deal, we added an additional 2.74 million barrels of crude oil hedges to the portfolio at an average price of $82.29 per barrel. All of these additional hedges have been in the form of straight swaps.
Assuming the second half 2013 through fiscal year 2017 pro forma expected production, including the Postle acquisition, our production is hedged at 85% for the second half of 2013, 77% in the year 2014, 71% in 2015, 55% in 2016 and 24% in 2017. Average annual prices during this period range between $84.11 and $95 per barrel of oil and $4.34 and $5.75 per MMBtu forecast.
I would like to note that our goal is to consistently hedge a high percentage of future production with swaps and costless collars. 96% of our hedge portfolio consists of swaps and costless collars, and only 4% is comprised of productions. We will of course expect to add additional oil and gas hedges throughout the rest of the year to maximize the economics of our current and future production.
An updated version of our commodity price protection portfolio, presentation summarizing our hedges, will be available in the events and presentations section of the Investor Relations tab on our website shortly.
As for our overall liquidity position, our outstanding debt balance as of July 15th following the Postle transaction closing was approximately $1.8 billion and consisted of borrowings of $1.05 billion on our credit facility and approximately $756 million in senior notes.
As of today, we had approximately $1.03 billion outstanding under our credit facility, which has a borrowing base of $1.5 billion and an elected commitment amount of $1.4 billion. So we have just under $400 million in undrawn liquidity.
Our debt to LTM pro forma adjusted EBITDA ratio for the third quarter will be about four times, which is well within the modified leverage ratio covenant per the amended credit facility of four and three quarter times for the third quarter of 2013.
Recall that our amended credit facility has modified ratio covenants for a period of five quarters following transaction, which enhances our flexibility to reduce our leverage using cash flow and/or opportunistic financings or other transactions over time.
Our current leverage is consistent with our leverage profile following our 2012 acquisition activity. While we’re comfortable at these levels, we remain consistent with our financing strategy, and as always, are watching the markets closely for opportunities to reduce our short term debt and fund future growth.
This concludes our formal remarks. Operator you may now open the call for questions.
And we will take our first question from Ethan Bellamy with Baird.
Ethan Bellamy - Baird
Two big picture questions. First, why didn’t you concurrently equity finance the recent transaction? And then secondly, with respect to maintenance CapEx, what assurances can you give us that your maintenance CapEx is sufficient to maintain production? And can you provide us with some granularity or transparency about how you go about calculating that number?
Jim, once you handle the financing question and Mark, why don’t you take maintenance CapEx.
Ethan, its Jim. Regarding financing, we’re constantly looking at the financing markets. The Postle negotiations, that transaction, it took an extended amount of time. We’ll continue to look at how to finance the Postle acquisition, reduce short term debt. But for a host of reasons it just wasn’t practical for us to simultaneously finance that on the equity side concurrent with the announcement.
Mark, do you want to handle the maintenance CapEx?
Okay, I’ll follow up with that. Ethan, when we look at our maintenance capital, I think, going forward really important things here and I think probably everybody on the call knows but we define maintenance capital as the amount of investment it takes the hold production flat. And we look at it regularly, Ethan, and what we use as the basis for those calculations is a year-end reserve report. And probably everybody knows that they may not, that sort of reserve report that’s a complete determination by external reserve auditors. And we look at multiple years on that reserve report.
So we don’t cherry pick a year and we don’t try to put the properties or projects that are more capital efficient. We don't try to lump all those in one year. So we look at our reserve report. We take our exit rate for the latest year in that reserve report and then we look at the reserve report and see how our rates vary out in the future. And if for instance our base declines 10% and we look at the time period that production covers and it goes up, production goes up 5%, then we say that two thirds of the money that’s been spent because it’s actually grown from our base, we’ve grown 15%, two thirds of the money that we spent is needed to cover that 10% base decline. So that’s the details behind it and it’s all backed up by what we have in the reserve report.
Additionally, we added some additional capital in there. That’s what we call a mandatory capital. As we look in those out years, if we don’t believe there is enough mandatory capital for projects that we’re required to do, we add additional mandatory capital in there. So that's a long answer to your question, but it's all tied to our reserve report.
Ethan Bellamy - Baird
And historically speaking when you've done that exercise, how have your projections about the production from the dollars been? How have those been born out versus your estimates when you are making that maintenance CapEx budget?
I think as a whole they have been very good Ethan. That's one of the things about having a bigger portfolio of projects, and some projects come in better than forecast, some come in under forecast. But as a whole, the program has matched closely.
And we will now go to Kevin Smith with Raymond James.
Kevin Smith - Raymond James
Can you talk about the integrations at the Postle field? How is that shaping up? Are you happy with the man power you have? Do you need to add anybody, things of that nature?
Hi Kevin this is Mark. I am glad you asked that question because this is something that we are spending a tremendous amount of time focusing on. I have been to the Postle field twice since we announced acquisition. Dave Baker who is our Senior VP of ops has been there twice. Hal was there a couple of weeks ago. We've all been to Midland and you may or may not know but it's critical in Postle to get all of the field group. And in fact I heard just the other day from Brian Door, who is our Vice President of Operations that will manage Postle, all of the Whiting field people have accepted our job offers. So that was very, very important to us.
The other part of that is we're working is the technical staff in Midland. We have had a number of meetings with them, we've been out there, we've made them all job offers and we expect to hear back on those offers in a couple of weeks. Just as an FYI they're all coming into the Houston office tomorrow to meet some of the staff here, get a little better idea of what our organization's like and look at some of our other projects that BreitBurn is working on.
So we're working on that issue very hard. We recognize that getting all those people is important. The technical people have skill set, that's very, very focused on Postle and CO2, and so we're doing everything we can to make sure that we bring that over. And we only have a transitional service period that runs through the end October. So, so far we are encouraged by what we have seen and hope to get the rest of technical folks in Midland.
Kevin Smith - Raymond James
And then the other side, I guess the Permian rig count, it looks like it's moving around a little bit from maybe what you were telling us in the first quarter, but only by like a rig. Any thoughts there? And then I think you are originally talking about getting down to, or least dropping two rigs by year end. Now it doesn't seem like you are going to.
Yes. One of the things that we haven't talked a lot about is CrownQuest runs 12 to 15 rigs. Not all those are on properties where we have an interest. And we work very closely with them. But they move rigs in and out of our properties to meet drilling windows for efficiency reasons and also take care of any continuous drilling clauses or drilling requirements that we have. So it's not like we have five rigs on our properties all the time. They move them in and out.
So any time, you look at a snapshot any one day, it could be different than what we tell you. But overall we'll end up drilling right on the number of wells we've forecasted at the start of the year. Some will happen a little sooner, some might be a little bit later. Once we take over drilling operations completely by the end of the year then it will be a leisure for you guys to follow up because we'll have rigs out there working just on our properties.
And we will now go to Noel Parks with Ladenburg Thalmann.
Noel Parks - Ladenburg Thalmann
I got a couple of questions, I was curious, at (Belridge you said that the well were doing better than the pre-drill expectations and just curious to hear what changed versus what you thought the wells would do?
I am, glad you asked the question, because I was going through my script. As I read I thought there was one more point I should add in there. We actually drilled 20 wells in the second quarter. We only had time to get 10 of those completed and I said that in the script. What I didn't say is we're completing the other 10 now. So they want to leave the impression that half of it would be completed. But the specific things that were changing on those completions out there is we're breaking up the overall interval into more separate frac jobs to make sure we get that complete interval stimulated. And I think that's the biggest thing. We're just doing smaller intervals and more of them is supposed to larger fewer intervals.
Noel Parks - Ladenburg Thalmann
Actually how thick is the section out there?
Overall I think it's about 100 feet, it varies across the field, 100, I think the thickest areas 150 feet.
Noel Parks - Ladenburg Thalmann
And one question for Jim. As you were talking about the new hedges that you had put on, I thought I heard you say at one point that you added some swaps at around $82. And that just seems low compared to recent prices. So I just wondered if I heard that right or is there NGLs in there or something.
Noel its Jim. You have heard it right. Those actually relate to prices in years that are way out on the curve, which is right around where I think the market is today. Those are out in 2016, 2017 et cetera.
And we will now got to Michael Peterson with MLV & Company.
Michael Peterson - MLV & Company
I want to ask a question kind of broadly talking about risk of the equity. Now you look at your current yield and it implies a level of underlying risk that doesn't necessarily foot with kind of the maturity and diversity of your portfolio. As you look at rising DCF and then you think about potentially continuing to grow the distribution at plus or minus but approximately 5% per annum versus allowing distribution coverage to increase to de-risk the name, how you compare those to and what else do you think that might be helpful to kind of illuminate to the street what the portfolio looks like?
This is Hal. We're constantly looking at our distribution policy. We believe that the last 13 quarters of consistent increases and planning for that into the future is the right policy today, but we are constantly looking at it. We are building our DCF coverage significantly in 2013. We don’t plan at this point to significantly increase the distributions but rather to take the slow and steady approach.
But if we find overtime that that strategy is not the right strategy, we can revisit whether growing distributions at a slower pace and allowing DCF coverage to increase is a better policy but we are constantly looking at it, thinking about it and talking to our investors about that.
Michael Peterson - MLV & Company
Given the growth that you are seeing via third party acquisitions, would it be reasonable to assume that we might see a larger component of your growth coming from organic PUD conversions and things like that, given the robust opportunities that you have now?
That’s one of the things that we have been working on over the last few years and we really are in a great position. We have a significant inventory of organic growth opportunities in our legacy assets on our oil properties. That wasn’t the case two or three years ago.
In addition to that, we also have hundreds if not probably north of a thousand gas drilling locations that are not on our books as PUDs that are, basically all are held by production acreage. They are projects that we will drill today just because the oil economics are too compelling. It’s hard to divert capital to gas. But they are projects that should gas prices increase, we would likely allocate capital.
So we are in a position where if the relative valuation of gas although changes, we can move toward gas drilling rather quickly and we do have a significant inventory of gas drilling opportunities and we have over the course now for the last three years built up a similar inventory of oil drilling opportunities.
That having been said, we are in the acquisition and exploitation business. So I don’t think that you are going to see us try to grow our production organically significantly. We are talking about kind of low to mid-single digit organic production growth as our target and our goal and that our real growth comes through acquisition. So as long as the acquisition market is as open as it is today, as long as there are many opportunities to buy assets that fit our model as we are today, I think that that will remain a key growth driver for the partnership.
And we will now go to Jeff Robertson with Barclays.
Jeff Robertson - Barclays
Mark, a question just circling back on maintenance capital. Can you talk about whether or not the addition of the Postle asset will have much of an impact on the overall corporate decline curve and the intensity of what you need to spend for maintenance capital?
Jeff we have looked at that and it is shallow decline, which is a good thing for us. Overall it doesn’t have much impact. It is pretty consistent with the maintenance capital that we see across the portfolio. So well we have some areas as you look at them individually, they are higher than others. From the whole portfolio standpoint Postle was right in there with the rest of our assets.
Jeff Robertson - Barclays
Can you share what the cash flow just from that asset might be versus the capital that wouldn’t be needed to keep it flat?
Jim, I don’t know what we have disclosed on the deal.
Jeff it is Jim. We have not given that level of detail on Postle to date.
And we will now go to Adam Leight with RBC Capital Markets.
Adam Leight - RBC Capital Markets
Just to go back on the refinancing, could you just give us a sense of what your current target or view on leverage is, and also if you have gotten any feedback. I know you got a down grade from S&P, what Moody’s is saying and whether you might get some response if you are a little bit more proactive or dynamic in your financing?
Okay so in terms of our current leverage profile and our target leverage profile, target leverage profile i.e. our run rate leverage levels policy there really has not changed in the last few years. Overall we would like to be with a normalized capital structure and absent any recent acquisitions right around three times debt to LTM pro forma EBITDA. We are obviously higher than that now, just having completed the Postle transaction which was large. We are committed overtime to working our way back down to those levels.
There are a lot of different ways to do that and you can rest assured that we are looking at all types of different ways to finance, refinance, moderate leverage. The good news is that there is built into the credit facility, not for an extended period of time but for some period of time the flexibility for us to pass markets opportunistically. We are not going to delay unnecessarily in that regard. So we are actively looking at refinancing opportunities. We were looking at the markets closely even before the Postle transaction.
So target leverage levels haven’t really changed. We did get one down grade at S&P. We've had discussions with Moody’s, we don’t expect any changes there. I think the high yield market is a sophisticated market. Those modest moves by the agencies don’t typically have a lot of impact on where bonds trade. I know you understand that Adam.
And then we certainly do care what the agencies think they are a very important constituent. We keep them close in terms of progress on the business and the business model. We were very much in touch with them following the Postle transaction with respect to our policies, refinancing intensions, refinancing options et cetera. So we take them very seriously and we will just continue to watch the markets very closely here.
Adam Leight - RBC Capital Markets
Moving away to a separate topic, you guys did better on your differentials this quarter which is good. Have you done any more investigation to try to put this in additional basis hedging?
Yes. We constantly looking at that and we have a very good hedge for our California production which is growing as well as the Florida production, both more tied to Brent; California tried very, very closely. The cost of extended periods of basis hedging our protection is still extremely high but we are continuing to monitor that and if the costs seem to make sense from a risk basis. It seems to be justified, we certainly would enter into those sorts of hedges or at least explore them.
Adam Leight - RBC Capital Markets
And then lastly, were there any significant timing differences between production sales this last quarter?
Other than in Florida - Mark go ahead.
That’s all Hal and it was mainly this issue that I talked about with regards to barging and we had difficultly gets barges scheduled into the loading facility. So we put a bunch production into the tanks there. So we should make that up in third quarter.
Adam Leight - RBC Capital Markets
I don’t know if you quantified that. I may have missed it.
I don’t think we gave an exact number but we were down 14,000 - 15,000 barrels compared to the prior quarter and essentially all of that reduction compared to the prior quarter was due to this barging issue.
We will now go to (inaudible) with Bank of America
Just wanted to get some clear tracking on that Florida production. Would you expect to recover all that lost production due to barge delays in third quarter or would it have been distributed in third and fourth quarter?
Right now, it’s always a little bit difficult exactly predicting barge schedules but expect to get it all in the third quarter.
And the last thing I was just on your integration (audio gap).
So far I think everything went positive. We recognized going in that as I mentioned in my earlier remarks that it’s a complex field. It takes a lot of both field and technical oversight to have some very sophisticated tools that they used to do that and we’re working hard to integrate those into BreitBurn's systems.
So, the only thing that is really outstanding right now is whether or not we’re going to be able to hire their technical group and we’re working hard to do that. I guess if that doesn’t happen that would be a negative surprise for us and we’ve got some backup plans in place. But so far it’s so good I think.
We will now go to John Ragozzino with RBC Capital Markets.
John Ragozzino - RBC Capital Markets
Just a couple quick housekeeping items. First Hal, you started to mention the effect that the deal close slightly early. Would the guidance issued on the June 24th reflecting a full contribution as of the close on August 1st, should we expect basically the production contribution from the Postle to be about a 110,000 barrels greater than what we would have seen if it did close on the first?
John that’s correct. When we issued guidance, we were targeting an August 1st close. We were able to get it done little earlier. Overall it’s about 110,000 barrels, you’re right, but in the overall scheme of things, we didn’t think that was worth updating guidance for.
John Ragozzino - RBC Capital Markets
And then just a little bit more on differentials. Have you guys changed your outlooks for full year, just given the volatility seen in of some of the regional base in differentials?
John, this is Mark. I don’t think so. We had a little bit of improvement in some of the areas from Q1 to Q2. And we look at history, there will be some of the areas as we go into Q4, for instance Wyoming, typically, the differential increases in Wyoming because of the cold weather, a lot of that is heavy oil that’s used for asphalt paving those types of things, but overall I don t think we see big changes going into second half of the year.
John Ragozzino - RBC Capital Markets
And then Jim,, given where we've been over the last month with the stock ranging from close to $15 to $19, can you kind of quantify or just give us your thoughts on when you think about this biting the bullet and coming to equity markets and getting the financing out of the way and kind of getting on with the business model. Is that something you'd consider more that $19 or $20 than you did at $15?
John, its Jim. I would say, we really do and look at the markets every day and we certainly are of the view, as I think somebody pointed out earlier that we trade on a relative basis at a discount to the peer group, particularly given our track record in acquisitions on a track record with distribution growth. I think it’s a requirement that management always would like to see the stock price higher. That’s part of what we think out every day. But in terms of giving you a specific target where we’re comfortable financing, really it’s just not going to do that because it involves too many things. But we are looking at the markets all the time.
(Operator Instructions). And there are no further questions. Mr. Washburn, I’ll turn the call back to you for any closing remarks.
Thank you, operator. On behalf of 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.
As a reminder, the correct replay number for international callers is (858)-384-5517. Once again that number (858)-384-5517. And this does concludes today’s conference all. Thank you everyone for joining us and you may now disconnect.
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