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

Q1 2013 Earnings Call

May 3, 2013 12:00 PM ET

Executives

James Jackson - Executive Vice President and Chief Financial Office

Halbert Washburn - Director and Chief Executive Officer

Mark Pease - President and Chief Operating Officer

David Baker - Vice President, Eastern Division

Analysts

Adam Leight - RBC Capital Markets

Michael Peterson - MLV & Company

Noel Parks - Ladenburg Thalmann

James Spicer - Wells Fargo

Aaron Terry - Kayne Anderson

Bernie Colson - Global Hunter Securities

Jeff Robertson - Barclays

Operator

Welcome to the BreitBurn Energy Partners' investor conference call. The partnership's news release made earlier today is available on its website at www.breitburn.com. (Operator Instructions) I would now like to turn the conference over to Jim Jackson, BreitBurn's Executive Vice President and Chief Financial Officer.

James Jackson

Thank you, and good morning, everyone. Participating with me this morning are Hal Washburn, BreitBurn's CEO; and Mark Pease, BreitBurn's President and Chief Operating Officer. After our formal remarks, we will open the call 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 estimate today and are based upon our current expectations and assumptions about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change from those we projected over the course of the year.

A detailed discussion of many of these uncertainties is set forth in the cautionary statement relative to forward-looking information section of today's release and under the heading Risk Factors incorporated by reference from our annual report on Form 10-K currently filed 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 or events.

Additionally, during the course of today's discussion, management will refer to adjusted EBITDA which is a non-GAAP financial measure, when discussing the partnership's financial results. Adjusted EBITDA is reconciled to its most directly comparable GAAP measure in the earnings press release made earlier this morning and posted on the Partnership's website. This non-GAAP financial measure should not be considered as an 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.

Halbert Washburn

Thanks, Jim. Welcome, everyone, and thank you for joining us today to discuss our first quarter 2013 results. I'm pleased to say that the partnership was off to a good start, for what we expected to be a very productive year. We've already put our capital program with $261 million, $97 million of which will be directed to oil projects, the work on a series of low-risk oil drilling plays in California and Texas.

Our 2013 capital program will include the drilling and re-drilling of a 135 wells in five states, with up to a maximum of 11 rigs running. We started the planned ramp up this quarter. We drilled 16 wells, spud 22 more and currently have a total of five rigs running between Texas and California. Given the size and timing of our drilling projects and the typical seasonal weather restrictions, activity and production, particularly oil production, is scheduled to increase throughout the year as planned.

Early results, particularly in California and Texas, are better than we anticipated and remain on tract to get our 2013 production guidance of between 9.5 and 10.1 million Boe. And meet our target of exiting the year, producing between 27,700 and 28,850 Boe per day, 51% of which will be oil and 4% NGL.

Now, I'll briefly go over first quarter highlights. Net production for the quarter was approximately 2.35 million Boe, which was a record quarterly high quarter partnership and a 6% increase over the prior quarter. We also increased our net liquids production to a record quarterly high of 1.21 million barrels or 51% of total net production.

The increase in production and changes in production mix, reflected the benefit of recent acquisitions and accelerated oil drilling program in our legacy assets, as well as better than expected drilling results in our recently acquired properties in Texas and California. Other key operating metrics, including the timing of our capital plan and our ongoing focus on expense control are also on plan. Mark will discuss more details on operating results later in the call.

Adjusted EBITDA for the first quarter was $64.1 million compared to $78 million in the fourth quarter of 2012. While we expected a decrease due to lower average strike prices on our WTI, Brent and natural gas hedges, we also had weak oil differentials in Wyoming and Texas, weaker natural gas differentials in Michigan. And like many of our peers wider than expected NGL market prices in Texas.

Just to add some additional detail, out full year weighted average floor prices for our WTI, Brent and natural gas hedges were $98.80 per barrel, $105.46 per barrel and $7.12 per Mcf in 2012. Those average hedge floor prices stepped down significantly in 2013 to $89.21 per barrel for WTI, $97.57 per barrel for Brent and $5.87 per Mcf. So in some cases were as much as 18%.

With respect to NGL differentials was saw them widen from approximately 53% of WTI late in the fourth quarter of 2012, so approximately 30% of WTI in the first quarter of 2013. Also weighing on the result this quarter is the ongoing curtailment production from certain Texas fields acquired in July and December of last year.

The successful acquisition strategy last year and the size of our oil centric 2013 capital program are both designed to offset the built-in decline and hedge price from last year to this year. Our capital program is focused almost exclusively on oil projects, which have very attractive margins. And we are forecasting liquids production to grow over 35% from the fourth quarter of 2012 to the fourth quarter of 2013.

With that, I'd like to discuss distributions. We're pleased to have recently announced our first quarter 2013 distribution of $0.475 per unit or $1.90 per unit on an annualized basis. This represents a 4% increase from our first quarter 2012 distribution and marks our 12th consecutive quarterly distribution increase.

Our coverage ratio for the quarter was 0.67 times, which for this short term is well below our target range of 1.1 to 1.2 times. However, we have planned for our coverage ratio to increase dramatically throughout the year, even before the benefit of accretive acquisitions. Based on our capital program and change in production mix with an emphasis on oil, we expect our distribution coverage ratio to increase to slightly below 1 times during the second quarter and to increase to our target range of 1.1 to 1.2 times in the fourth quarter.

As I have said before, our ability to grow distributions quarter-over-quarter is supported by our expanding operating plan and the ongoing success of our growth through acquisition strategy. We're committed to delivering best-in-class distribution growth among our E&P MLP peers.

On the acquisition front, we continue to be very active and disciplined in pursuing new opportunities to grow the business. If you recall, last year was one of our most successful year in the acquisitions market. We exceeded our 2012 acquisition target of $300 million to $500 million by completing seven major acquisitions, totaling over $600 million. This year we are no less ambitious.

During the first quarter we reviewed almost 150 opportunities, which is significantly more than we had reviewed by this time last year. We are targeting primarily oil acquisitions in our key operating areas or where the targeted fields meet our criteria of having significant original oil in place and attractive low risk organic growth opportunities.

We are confident we'll reach our goal of completing at least $500 million in acquisitions this year. $500 million can truly move the needle for business of our size. By a way of example, a hypothetical acquisition purchase based on a forward adjusted EBITDA multiple of 6 times could potentially add approximately $23 million to distributable cash flow over the course of year or about $0.21 per unit. Of course, every transaction is different, but this is just an example of distributable cash flow accretion that can be generated by acquisitions in our target range.

We're very well-positioned financially to remain active in the acquisition market. Our two most recent financings were very successful. These include the bond offering in September 2012 and a significant equity offering in February of 2013 that raised a combined total of approximately $485 million in proceeds, all of which was used to pay down borrowings under our credit facility.

As of today, we have approximately $100 million in outstanding bank borrowings. While these financing in the short-term reduce our current distributable cash flow coverage ratio, they give us considerable financial flexibility to acquire attractive assets or companies that fit our business model.

We're off to a strong start to an exciting year. The rollout of our oil focus capital program is on plan and the results to date have been very encouraging. We're very active in reviewing potential acquisition opportunities and are poised to move quickly on the right opportunity. We have a highly liquid balance sheet, providing us with almost $800 million in borrowing capacity, which is well above our $500 million goal for acquisitions this year.

With that, I'll turn the call over to Mark, who will discuss operating results for the quarter.

Mark Pease

Thanks, Hal. We had a very active first quarter and our capital program progressed as planned with the completion of 16 gross, 11.5 net drilled wells, and 10 workovers, which combined, added incremental net production of about 1,100 Boe per day. We spent a total of about $45 million in capital for the quarter that was essentially all focused oil projects.

We also delivered record quarterly net production of 2.35 million Boe, which is 6% higher than the fourth quarter of 2012. This increase was primarily the result of the acquisitions that closed at yearend 2012, and increased development activity on our legacy assets.

Production mix for the quarter was about 51% oil and NGLs and 49% natural gas compared to 45% oil and NGLs and 55% natural gas for the prior quarter. So as you can see, liquids production has increase considerably due to our continued emphasis on oil.

Oil production alone, increased by 13% from the prior quarter and 28% from the first quarter of 2012. Lease operating expense and processing fees for the first quarter, excluding production and property taxes, were $19.42 per Boe, which is right in the middle of our guidance range.

Now, let's walk through the different operating areas by state. First, let's talk about California. Results from our California operations were very good for the quarter. Production came in at 376,000 Boe, which is right at what we expected. Capital expenditures in California totaled $15.1 million for the quarter, and included four new 100% working interest drill wells and four workovers, which added incremental net production of about 430 Boe per day compared to the projected 150 Boe per day.

Our subsurface team has done and continues to do an excellent job, identifying additional growing prospects in our Santa Fe Springs field. We expect to run one rig in Santa Fe Springs for all of 2013, and will drill a total of 26 100% working interest wells. Over the past year, we purchased additional minerals in the field that have expanded our growing inventory. So Santa Fe Springs will continue to be an area of focus for us.

In the Belridge fields, one of the acquisitions that we closed at yearend 2012, there was no drilling activity during Q1. However, we spud our first well there in early April, and the rig will run until late June drilling a total of 20 100% working interest wells.

We expect to spend a total of just over $80 million for the full year in California. California controllable lease operating expense was $12.9 million for the quarter. This was slightly higher than our original forecast, largely due to the ongoing work at Santa Fe Springs.

Turning to our Texas operations. Net production for the quarter came in at 331,000 Boe, which was slightly below our forecast. This reflects the increasing gas curtailment we are seeing, most of which should be resolved by the third quarter. The gas curtailment will somewhat offset by better than projected performance on the new drill wells.

However, gas curtailment continues to be an issue in West Texas, and we're working closely with our gas purchasers to minimize those impacts going forward. Capital expenditures in Texas totaled $19.7 million for the quarter and included the drilling in completion of 9 gross 4.6 net new drill wells, which added incremental net initial production of 510 Boe per day compared to the projected 398 Boe per day.

We started the first quarter with two rigs running and increased our rig count to four rigs by the end of the quarter. We expect to pickup two additional rigs by mid year for a total of six, and should finish the year with two rigs working. We're planning on spending over $95 million for the full year in Texas or drill a total of 60 gross, 38.7 net new wells. So it's going to be a busy year for us. Controllable LOE for the quarter averaged $7.62 per Boe, which makes Texas our lowest cost operating area.

The integration of the Permian assets is progressing well. On January 1, 2013, BreitBurn assumed operations of the Permian properties we have acquired in the CrownQuest acquisition last July. And on May 1, we took over operation of the second set of CrownQuest properties that were acquired in the December of 2012. During the quarter we also set up an office in Midland and are building our operating team.

Now, let's move North Wyoming. Production for the quarter was 619,000 Boe, which was slightly below our forecast. The lower production was mainly in our gas properties in Southwest Wyoming, and was primarily due to the harsh winter weather, which increased downtime compared to forecast and also increased the fuel gas required for hitting.

Recall, that we typically experienced lower production in the first half of the year for our operations in states with winter weather conditions. Because of the additional cost of working in the winter season, drilling activity was relatively slow. We completed 3 gross, 2.9 net wells that hadn't been started in 2012 and we finished the first quarter with no rigs working.

Capital expenditures for the quarter were about $4.8 million, which included the three drill wells and four workovers, which together added net incremental production of 175 Boe per day compared to the projected 91 Boe per day. Controllable LOE for the quarter came in at $12.32 per Boe, with slightly under forecast.

We did pick up a rig and spudded a well in early May, and we will pick up a second rig by the end of the second quarter. We expect to drill 18 gross, 15.8 net wells in 2013 in Wyoming and spend total capital of $27 million.

Now, let's go to Florida. We had a relatively quiet quarter. We finished drilling well that was started in 2012, and then farmed out the rig to another operator. Capital spending for the quarter was about $3.5 million and we are just finishing the completion on the new well. We expect to get the rig back in the second quarter and plan to drill a total of 4 gross 100% working interest wells in 2013, spending total capital of about $40 million.

Production for the quarter was 174,000 Boe, which was a little bit below forecast. Production was down mainly due to one well failure. The well is presently being evaluated for workover or a potential re-drill. We had a good quarter on operating expenses in Florida with cost coming in about 6% below our forecast.

The last area I want to touch on is Michigan, Indiana and Kentucky. We had a good quarter with operation too. Production for the quarter was 847,000 Boe, which is a little above forecast and reflects better than forecast production in the newly drilled DRZ oil wells at Beaver Creek, and in the existing Prairie du Chien wells. LOE for the quarter was essentially right on forecast.

Capital expenditures in Michigan totaled about $1.2 million for the quarter and included one conversion-to-injection and one recompletion, which added incremental net production of about 13 Boe per day and met our expectations. As this area is mainly natural gas, capital expenditure for the year expected to be about $13 million. These will be focused on the Detroit river oil zone to drill 7 gross 100% working interest wells.

So Q1 was a very busy quarter with production and cost essentially right on forecast to deliver in the middle of our guidance range for the year. As planned, there will be a strong ramp up in activity going from 5 rigs at the end of Q1 to 11 rigs by mid year. Program will drill 135 gross and 111.5 net wells.

We expect to spend 80% to 85% of our 2013 capital budget in the last three quarters of the year, essentially all-in-all projects. This should allow us to grow liquids production by over 35% from Q4 2012 to Q4 2013. Additionally, as we previously said, we're forecasting 2013 production to be between 9.5 and 10.1 million Boe for the December 2013 exit rate between 27,700 and 28,850 Boe per day. Providing we achieve the midpoint exit rate for 2013, it will be an increase of about 13% compared to the December 2012 average production rate.

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

James Jackson

Thank you, Mark. I'll cover a number of topics today, and we'll start with EBITDA and earnings. Adjusted EBITDA for the first quarter of 2013 was $64.1 million compared to $78 million in the fourth quarter of 2012.

While the first quarter adjusted EBITDA was up 4% year-over-year, it was lower than the prior quarter, due to as Hal mentioned significantly lower average hedge prices across our hedge book, weaker oil and natural gas differentials in selective states, weaker NGL pricing overall, and continued curtailment in Texas. I will discuss how we expect adjusted EBITDA to trend over the course of the year and the impact on our distribution coverage ratio shortly.

Turning to earnings, we recorded a net loss of approximately $36.3 million or $0.38 per diluted common unit as compared to a net loss of $10.3 million or $0.13 per diluted common unit for the fourth quarter of 2012. The decrease was primarily due to lower realized hedge gains and higher unrealized losses on commodity derivative instruments as compared to the prior quarter.

Realized hedge gains were $5.1 million in the first quarter, down from $22.5 million in the prior quarter. Unrealized hedge losses increased to $29.4 million in the first quarter, up from $18.7 million in the prior quarter. Cash interest expense for the first quarter of 2013, including impact of realized losses on interest rate derivatives was $17.2 million compared to $17.4 million, excluding losses on terminations for the fourth quarter of 2012.

Now, I'd like to discuss distributable cash flow for the quarter. Distributable cash flow was approximately $32.1 million in the first quarter. This amount reflects adjusted EBITDA of $64.1 million, less cash interest expense of $17.2 million, less than assumed amount for maintenance capital of approximately $14.8 million. We define maintenance capital as that amount of annual investment required to keep production approximately flat year-over-year.

On per unit basis, distributable cash flow was approximately $0.32 per unit. Our coverage ratio for the quarter based on the $0.475 distribution paid on April 28 was 0.67 times. In any given year, the first quarter is typically our weakest quarter for distribution coverage ratio. We generally have seasonal production issues due to weather in Wyoming and Michigan, but this quarter we also had price differential and curtailment challenges that weighed on the quarter.

In addition, as Hal mentioned, our 2013 hedge prices are well below the 2012 level. Given the ramp up in our capital program and the changing production mix with an emphasis on oil, we expect 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. Of course, this is also before the benefit of any accretive acquisitions we might complete this year.

One additional comment here, our coverage ratio was also impacted by our overall liquidity position, which is very strong. Our current liquidity position benefits from a large 14.95 million common unit equity offering completed in February and a $200 million opportunistic high yield offering done last fall.

Proceeds from those transactions we used to pay down the borrowings under our bank credit facility. Had we now complete those offerings, our pro forma distribution coverage for the quarter would have been approximately 0.83 times. Given our current liquidity position and absent of significant acquisition, we have no immediate need to access the equity market at this time.

Turning to our hedging activity. We continue to see our hedge book play an integral role in mitigating commodity price volatility, particularly with natural gas. Our realized natural gas prices for the first quarter averaged $5.43 per Mcf compared to Henry Hub natural gas spot prices of $3.49 per Mcf.

On the oil side, average realized crude oil and liquids prices were $78.12 per barrel compared to NYMEX crude oil spot prices of approximately $94.33 per barrel. The inclusion of Texas NGLs is bringing this number down obviously.

Crude oil realized price, excluding all NGLs, was approximately $83.50 in the first quarter compared to $93.83 in the fourth quarter of 2012. The decrease was primarily due to lower average hedge prices. Also realized prices for NGLs in the first quarter were $26.32 per Boe.

Brent crude oil spot prices, which are an important benchmark for our California oil production, averaged $112.44 per barrel in the first quarter of 2013 compared to $110.15 in the fourth quarter of 2012.

In keeping with our policy of systematically expanding our hedge portfolio, during the quarter we hedged approximately 3.4 million barrels of oil production for the period covering the second quarter of 2013 through 2017, at average prices of $93.62 per barrel. And we hedged 3.3 Bcf of natural gas production for the period covering 2016 to 2017 at an average price of $4.45 per MMBtu.

In total, we increased our net volumes hedged by just over 2 million Boe during the quarter. More recently in April, we added more gas hedges to the portfolio hedging 0.9 Bcf in volumes for the second half of 2013 at $4.34 per MMBtu.

Assuming a midpoint of our 2013 production guidance, which is 9.8 million Boe is held flat. Our production is hedged at 79% for the nine months ending 2013, 74% in 2014, 71% in 2015, 49% in 2016, and 10% in 2017. Average annual prices during this period range between $88.20 and $95.17 per barrel of oil, and $4.31 and $5.79 per MMBtu for gas. Our hedge book consist principally of swaps and costless collars, which makeup 95% of our total hedged volumes.

As a policy, we have also increased our overall headings targets. Our goal is to be 80% hedged in year one, 75% hedged in year two, 78% hedged in year three, 60% hedged in year four, and 50% hedged in year five. We expect to add additional oil and gas hedges throughout the year to achieve these targets. And we'll continue our practice of hedging acquisitions very aggressively.

One additional comment regarding our hedge book. Hal reviewed the year-over-year change in hedges, the strike prices earlier, but fortunately our 2013 average strike prices are stable throughout the year. Looking forward and based on our existing hedge portfolio, our 2014 averaged gas hedge price declines approximately $0.80 per MMBtu versus 2013's average price. But our average oil hedge price increases by approximately $2.20 from 2013 to '14.

The point being, we don't face the same headwinds with respect to our 2013, 2014 and 2015 hedge price decline that we did going from the prior quarter to this quarter and from 2012 to 2013. A current version of our commodity price protection portfolio presentation, summarizing our hedges, is available in the Events and Presentation section of the Investor Relations tab on our website.

As for our liquidity position, our outstanding debt balance as of March 31, was approximately $841 million and consisted of borrowings of $85 million under our revolving credit facility, and approximately $756 million in senior notes. As of today, we had approximately $100 million outstanding under our credit facility, which has a borrowing base limit of $900 million. As you can see, we are very well positioned to continue to go through acquisitions in 2013.

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

Question-and-Answer Session

Operator

(Operator Instructions) And we'll take our first question from Adam Leight with RBC Capital Markets.

Adam Leight - RBC Capital Markets

Can you clarify a little bit more to pricing what were your unhedged crude price for the quarter and maybe if its warranted, break it down a little bit by region?

James Jackson

So, let me do this, let me give you oil and NGLs hedged and unhedged. So on the oil side for the quarter, realized prices before hedges for oil around $90.50. And realized prices for oil, including realized hedged losses was around $83.30. But we do not have any NGL hedges, so our realized price per Boe in the quarter or NGL is around $26.30.

Adam Leight - RBC Capital Markets

And so the realized hedge for the hedged losses were based on swaps that were at that low price, is that correct or is there something else in there? And that what does that look like in the second quarter?

James Jackson

The strike prices on the oil and the gas side are flat throughout the year. And we don't expect quarter-to-quarter, we don't expect a material changes in terms of realized gains and losses assuming commodity prices stay the same. We don't have any real notable variability quarter-to-quarter in the hedge book in terms of price, Adam.

Adam Leight - RBC Capital Markets

And then just can you give us what the percentage NGL production was set under 5% and does that changed going forward?

Halbert Washburn

Adam, it was right at 4% and that's about what it will be all year.

Operator

We'll take our next question from Michael Peterson with MLV & Company.

Michael Peterson - MLV & Company

Mark, I'd like to a follow-up on the detail that you gave operationally. First, I appreciate all that granularity. You noted better than expected drilling results, California, Texas and Wyoming and particularly in California. What was the source of the surprise? What do you know now that you didn't know before you spud?

Mark Pease

I think it's a number of things, Michael. And I appreciate the question. I mean it's mainly Santa Fe Springs. We haven't really started in Belridge yet. But we've done a tremendous amount of subsurface work in that field the last year. And you know it's an old field, it was discovered back in the 1920s and the more work we've done, the more we're learning about faulting and compartmentalization. We just completed a 3D survey.

So we're locating the bottom hole locations on these well and areas that haven't had as much granularity, so we're getting a little bit higher pressure. This field has been water flooded for years. We're not only getting little bit of higher pressure in the wells, we're getting higher oil cuts and also more natural gas. So maybe the short version is that, it's better placement of wells in areas that haven't been drained as much, both to subsurface geological work and geophysical work.

Michael Peterson - MLV & Company

Do you feel like, let's say, for the next four or eight wells that you drill, are your expectations going to be for something in the 400 or 430 kind of the range or some more between that and prior expectations?

Mark Pease

We don't know Michael. I mean, these wells are tight curve is as you can tell from the comments we made about our projection, it's significantly lower than that. And the rate of return on this thing is very, very attractive on a tight curve. So we're looking at program this year and if the results continue to be better than our tight curve then we'll bump it up. But for right now, we're sticking with tight curve forecast.

Michael Peterson - MLV & Company

Something for Jim or Hal. You noted an accelerated amount of deal streaming year-to-date so far. Is that a function of more staff as you allocated more focus to do that, I suspect certainly, fourth quarter of last year was pretty frothy and lots of things were coming your way. What's the reason for the acceleration?

James Jackson

We have been building the team and we built the team significantly last year through the course of the year, so we have the capacity to look at a lot of transactions. We were just starting that real build in the first quarter of last year. So we feel we're looking at virtually, if not every deal that is all appropriate for us here in the North America and that's important to us. We want to make sure we see everything.

Operator

We'll take the next question from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Just a few things, could you talk a little bit about, now that you've assumed operatorship of additional properties in Texas. Just what your, I guess positive going what you are seeing, and also if you have any updates on how performance of the Wolfberry has been?

Mark Pease

We have been very, very pleased with the results from our new wells that we're drilling out there. They're coming in better than our forecasted tight curve. So we're pleased with that. And then as I mentioned in the script, one of the things that we're battling out there is curtailment. And I am sure that you guys, I've heard that from more than operator, but there are lot of activity out in West Texas.

So we currently have some of our production curtailed. We expect most of that curtailment to go away by in terms of time during the third quarter. And our mission right now is to continue work very, very closely with our gas gathers, so that they know what our drilling plans are and so we're placing wells in the area that are least likely to get curtailed, but that' going to be an ongoing project and we're working on that closely.

Another comment I'll make about our stuff in West Texas, is right now we are just drilling vertical wells. And in the area, not very far from that there is some horizontal drilling going on. Not only in the Wolfberry, but in some of the other zones adjacent to the Wolfberry, so we're watching that closely.

So we see that as a potential upside out. So I guess the short version is that we're very pleased with what we're seeing and we need to stay of top of the gas gathering. And we're getting our feet on the ground out there and getting comfortable with the operations. We've got a very good core of an operating team. And so that's going to be the key for us to stay on top of that business.

Noel Parks - Ladenburg Thalmann

Just wondering, you talked about other operators activity doing horizontal and so forth. Is the acreage situation locked up enough near where you are that other folks are all they are concerned about keeping information tight or are they're being very sort of cautious and restrictive with what they let out?

Halbert Washburn

I think it depends on how new the idea is in the certain area. The stuff that's real close up, it's they are just starting some horizontal drilling there. So we're not hearing lot of details, but as you move further away where they have been drilling horizontals longer, then those details are pretty public. I mean you can go on the websites of the company work in there and they got tight curves, et cetera

One of the key reasons we wanted to be on West Texas, but there are lot of people like CrownQuest, their business models is very complimentary about it. So they go out and pick up acreage, they do a fine amount work in finding that acreage, but they don't want to go completely through development. So then they turn that acreage. So as these people start getting ready to sell assets, move on to the next play, you learn a lot as you go in and look at those deals with them.

Noel Parks - Ladenburg Thalmann

Just curious, something for Jim, your new hedged targets, what led you to head in the direction, you have a little bit more aggressive with hedging?

James Jackson

Well, maybe actually little more conservative in terms of hedging. As we just look at the business model, I mean we are more comfortable with a additional hedges early on, frankly we made some progress with the bank group in terms of our ability to extend hedge portfolio, kind of across the curve to higher levels than we were historically restricted to. And I think now we are just responding to investor interest in seeing us more hedged particularly overtime in the out years.

Noel Parks - Ladenburg Thalmann

One housekeeping thing. The interest expense item for the quarter was a bit higher than I was expecting, though I realized that might just be because of the balance of capitalized interest, might have been lower. Was there anything non-obvious going on in that line.

James Jackson

No, that's pretty straight forward from our perspective, nothing notable there.

Noel Parks - Ladenburg Thalmann

So capitalized interest level was above what you expected?

James Jackson

Yes, that's correct.

Operator

Our next question comes from (Mike Gaden) with RW Baird.

Unidentified Analyst

Can I please ask you a little bit more about the differentials realized in the quarter and specifically can you talk about the Wyoming and Texas differentials realized in Q1 discreetly as well as what they are turning to today and your outlook for those differentials over the balance of the year?

James Jackson

Let me make a little comment about that. The two areas where we really saw differentials change, particularly on the oil side from the fourth quarter to the first quarter, it was first in Wyoming. Differentials lined out there by call it another 40% and going from the 85% of WTI range to the 75% range, which is pretty meaningful. We do see some seasonality there. But even now, it was little wider than we anticipated.

And then in Texas on the oil side, differentials doubled versus our experience in the second quarter. And the second quarter oil differentials in Texas and this was just crude oil, this isn't a crude oil and NGL combined number, those just for around 93% in the fourth quarter, they wind out to about 87% in the first quarter. Now, we had slightly better this in California, but certainly not enough to offset the period-over-period changes in Wyoming and Texas.

Unidentified Analyst

Do you have a view on how those differentials should trend in the current quarter and over the balance of the year?

Halbert Washburn

We are not sure what's the differentials are going to do. We're looking at hedging basis risk and evaluating that. And we have seen a lot of volatility historically in Wyoming differentials. That's continued, as Jim said, it's generally been on quite a bit higher in the winter months. And narrowed significantly as the weather changed and there was more demand in the north Rockies, in West Texas. Everybody is pretty familiar what's going on there and a lot of take away capacity being constructed, a lot of well capacity that's been expanded. So our belief is over time that we'll narrow but it will be over time.

Unidentified Analyst

And can I lastly ask about NGLs, can you talk about the capitalization of your NGL barrel and what I'm trying to get at is trying to figure out why your NGL pricing differ so substantially from what we see listed, any color there would also be appreciated?

James Jackson

It really shouldn't differ from what you're seeing on the rest. It's pretty standard. Our contracts are very typical contracts. It shouldn't be different. So I'm not sure, I can comment on that.

Operator

Our next question comes from James Spicer with Wells Fargo.

James Spicer - Wells Fargo

Just curious about your full year 2013 guidance for EBITDA and then I guess also the differentials, although it sounds like your not sure where those were gone. Do you have any revised thoughts around that?

Halbert Washburn

We had some operational issues and some differential issues. NGLs in particular we talked about first quarter, but we are standing by the full year guidance that we have on all accounts. And we expect we'll be able to makeup significantly what shortfall that may have been in the first quarter. We expect production across the in line. So at this point, we are not going to change the guidance.

James Spicer - Wells Fargo

You don't have any acquisitions incorporated into those numbers, do you?

Halbert Washburn

That's correct. No acquisitions. So guidance assumes just the current properties. I think, James, one point to make, I know we said in the prepared comments, but the production mix for the partnership is going to change pretty dramatically over the course of the year as we focus our cap spending on oil production. So we'll see NGL stay at about 4% of mix, but oil will come up and sort of oil will be over 50% to date versus low-40s year or so ago. So as the year goes by, you'll see a lot more high margin oil barrels being produced which from an EBITDA contribution perspective has pretty significant impact on the business.

Operator

Our next question comes from Aaron Terry with Kayne Anderson.

Aaron Terry - Kayne Anderson

I think most of my questions have been answered, mainly the other question I guess I'd had is could you talk a little bit more on where your Wyoming production is today? How much of that is oil and maybe where you sell that production into?

Halbert Washburn

Our Northern Wyoming assets are almost exclusively crude oil and Southwest Wyoming is primarily almost exclusively dry natural gas. And I let the David Baker who is our VP of Operations give you a little more color on kind of the markets.

David Baker

In Wyoming, in general is about two-thirds of our production is oil and a one-third comes from the Southwest Wyoming property. The gas there is primarily sold to Anadarko, in Southwest Wyoming and then as the oil properties are primarily sold to Marathon.

Aaron Terry - Kayne Anderson

And the as far as production, I think the last number I saw was somewhere around 7,000 to 7,200. Is that a pretty fair number for Boe a day in Wyoming?

Halbert Washburn

About 7,000 Boe per day.

Operator

Our next question comes from Bernie Colson with Global Hunter Securities.

Bernie Colson - Global Hunter Securities

Am I correct to say you guys got a full kind of run rate of EBITDA from the acquisitions in December or was there something that prevented you from getting that?

Halbert Washburn

No, because we closed some of deals in December. So we did not get a full run rate of EBITDA from deals that closed during that month. We've got a partial month.

Bernie Colson - Global Hunter Securities

You had partial December, but you've got full first quarter?

Halbert Washburn

Yes.

Bernie Colson - Global Hunter Securities

Now, I am just trying of maybe follow-up on this differentials question because I guess there is a slightly different way to ask the same question, but if you make your way backup to that 1.1 or 1.2 times coverage ratio, what is baked into that as far as the differentials go? I mean are they recovering full year or you're assuming continued weakness or I am just trying to figure out what's kind of baked into that guidance?

Halbert Washburn

We are looking at more historical averages, so there will be some recovery, but not recovering fully into that and again the key to drive to that the increase in EBITDA is the growth in the oil production, especially the California oil production where we get premium. We're building that oil production as well as oil in West Texas and Wyoming. So really what you see is a production mix change. Your Boe margin on natural gas is a fraction of what it is on crude oil. But if you see the production mix changed to 55% or so liquids over the course of the year that drives a pretty significant increase in EBITDA per barrel and overall EBITDA on cash flow for partnership.

Bernie Colson - Global Hunter Securities

And then the question also kind of applied to NGLs, the guidance doesn't include a sharp increase in NGL prices for the remainder of the year, I know it's only 4% of production, but it seems like those two issues had a pretty descent size backed back in the quarter.

Halbert Washburn

We're still evaluating NGLs at this point and what our options are on that, but again it doesn't makeup the huge percentage of the production mix. It makes up 4% so well it's important it's not a real driver here.

Operator

Our next question comes from Jeff Robertson with Barclays.

Jeff Robertson - Barclays

Do you have any thoughts on whether or not the shift towards more capital on oil projects will have an impact and how we should think about maintenance capital going forward?

Halbert Washburn

When we look at maintenance capital, we're looking out five years and we're looking at our reserve report and our capital plans for that five period, and still comfortable with the 23% of EBITDA, 20% to 25% range. And so I think that looks pretty good with oil prices high, that drives it up higher then it would be the actual dollars as prices come down, we see goods and services tend to track down too. So we feel good about those numbers, but obviously we're looking at it. We look at it each year and look forward to make sure that they still stand up.

Jeff Robertson - Barclays

Secondly, with respect to incremental acquisitions, does the lift in the forward curve for gas, has that brought out any assets that are more attractive or has it made you think any differently about the relative attractiveness between gas and oil assets?

Halbert Washburn

Sure, we are focusing on oil, but there are number of gas deals that are out there and if we can get a good price, it's very accretive at point on both and NAV basis and distributable cash flow basis. We certainly won't say no, but most of the gas fields today have got a significant component of drilling that is marginally economic at the current strip. And so we're not going to commit significantly to add to our portfolio gas projects at least not, certainly not put much value on those.

As you know we've got thousands, hundreds of locations in Southwest Wyoming and hundreds of locations in Michigan for gas development. So we don't feel need to add to that portfolio today. But if the right deal comes along its very accretive and fits with what we're doing and certainly not going to just slip it out of our hand, but our focus is really more on liquids and oil.

Operator

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

Halbert Washburn

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

Operator

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

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