Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

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

Q4 2012 Results Earnings Call

February 28, 2013 1:00 PM ET

Executives

Greg Brown - Executive Vice President, General Counsel and CAO

Hal Washburn - Chief Executive Officer

Mark Pease - President and COO

Jim Jackson - Chief Financial Officer

Analysts

Ethan Bellamy - Baird

Kevin Smith - Raymond James

Praneeth Satish - Wells Fargo

Noel Parks - Ladenburg Thalmann

Michael Peterson - MLV & Co.

Operator

Please standby, we are about to begin. Good day, 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, all 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, February 28, 2013. A replay of the call will be accessible until midnight, Thursday, March 14th by dialing 877-870-5176 and entering conference ID 8245339. International callers should dial 858-384-5517. An archive of this call will also be available on the BreitBurn website at www.breitburn.com.

I would now like to turn the call over to Greg Brown, Executive Vice President, General Counsel and Chief Administrative Officer of BreitBurn. Please go ahead, sir.

Greg Brown

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

Let me remind you that today’s conference call contains forward-looking statements within the meaning of the federal securities laws. All statements other than statements of historical facts that address future activities and outcomes are forward-looking statements.

These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ materially from those expressed or implied in such statements.

These forward-looking statements are our best estimates today and are based upon our current expectations and assumptions about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change over the course of the year from those we projected.

A detailed discussion of many of these uncertainties is set forth in the cautionary statement relative to the 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 for the year ended December 31, 2012, which will be filed later today 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 future 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 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.

Hal Washburn

Thank you, Greg. Welcome everyone. Thank you for joining us today to discuss our fourth quarter and full year results. The Partnership had an exceptional year with record production, adjusted EBITDA and substantial acquisition activities that significantly grew our asset base.

Production for the year was 8.318 million Boe, an increase of 18% from 2011 and the highest yearly production in BreitBurn’s history. Adjusted EBITDA for the year was $295.8 million, an increase of 31% from 2011 and another record high for the Partnership.

Furthermore, we recently increase distributions for the 11th consecutive quarter. Our fourth quarter 2012 distribution was $0.47 per unit and for the full year we paid $1.85 per unit, representing a 7.2% increase over 2011’s total. We remain committed to consistent distribution growth supported by our growth through acquisition strategy.

We are very pleased to say that 2012 was the most active year for the Partnership on the acquisitions front with inclusion of seven acquisitions totalling over $600 million and the expansion of our geographic presence to seven states.

Most notable with the conclusion of five Permian Basin acquisitions that not only gave us a solid presence in Texas but also additional bolt-on opportunities in the region that otherwise would not have been available to our portfolio. The acquisitions were primarily oil at predictable development drilling outcome, include numerous potential drilling locations which expand our organic growth opportunities.

As I’ve mentioned before, the Permian Basin is always been an area of strong interest for the Partnership. We expect to remain active in the region and see Texas is a focal point in our overall operations.

During the fourth quarter, we also expanded our presence in California with the AEO acquisition in Kern County and in Wyoming with the NiMin bolt-on acquisition in the Big Horn Basin. The integration of these assets into our portfolio is going smoothly.

Both acquisitions are primarily oil and the properties have significant original oil in placed and unproved potential, which enhance our exposure to oil and organic drilling opportunities. In total, the acquired assets increased total prove reserves by approximately 34 million Boe and will meaningfully increase oil production in 2013.

We were an active acquirer in 2012 but we were also very selective, we adhere to our long standing disciplined approach to adding quality MLP assets to our portfolio that are accretive and will generate value to our unitholders for years to come.

During the year we screened almost 500 deals but closed only seven. In 2012 we focused on primarily oil assets that offers slightly higher PUD component with the intent of achieving a more balance portfolio.

While we expect acquisition activity to be robust this year, it’s important for us to have a meaningful inventory of organic growth opportunities in our portfolio. At the year end 2012, we have 20% PUDs which is twice as much as we had two years ago.

Similarly our oil to gas ratio at the end of 2012 was 53% oil, 47% gas, compared to 35% oil, 65% gas in 2010. As you can see, we now have a lot of flexibility and opportunities in the portfolio that allow us to maximize returns for investors even in weak market for natural gas.

Having completed over $600 million in acquisitions in 2012, we far exceeded our original target of $300 million to $500 million, a growth to de-modify our demonstrated ability to acquire. And we are confident we can complete effectively in what we believe will be a very active acquisition market in 2013.

Now, I’d like to briefly touch on our capital program for 2013. This year we had expanded our capital program to $261 million, including capitalized engineering costs, focused primarily on our oil assets in the Permian Basin, California, Florida and Wyoming.

We plan to drill and redrill 135 wells in five states and planned out five continuous drilling programs with up to 10 rigs running during the year. Mark will go over our capital program in detail later on.

Overall our performance in 2012 has positioned us very well to continue the momentum through 2013. We’re starting the year with a very strong balance sheet after a highly successful equity offering in February. We now have less than $100 million in outstanding borrowings under our credit facility which has a borrowing base up to $1 billion. Our undrawn revolver capacity gives us considerable financial flexibility to fund our growth this year.

Before I turn this over to Mark, I’d like to preview our 2013 guidance. Excluding acquisitions we’re projecting total production between 9.5 BOE and 10.1 million BOE. The midpoint of which is approximately 18% higher than our 2012 total production.

We project -- excuse me -- we projected adjusted EBITDA before any 2013 acquisitions to be between $330 million and $340 million, the midpoint of which is approximately 13% higher than our 2012 total adjusted EBITDA. We expect another active year and productive year for acquisitions and we’re targeting at least $500 million in acquisitions for the year.

Jim will provide further details related to guidance later in the call. We made significant progress towards our goal in 2012. And we believe the partnership is poised for another strong year in 2013. We’ll continue to focus on maximizing the value of our legacy and recently acquired assets with successful execution of our growth through acquisition strategy, mitigating commodity price volatility with an expanding hedge portfolio, all with a focus on supported and growing distributions to our unitholders.

Our results are reflection of the efforts of our employees. We want to thank them for their hard work and our investors for their continued support.

With that I’ll turn the call over to Mark, who’ll discuss our fourth quarter and full-year operating results as well as our 2013 capital program. Mark?

Mark Pease

Thank you, Hal. I’m pleased to say that we had very good operational performance during 2012. We closely managed our operating costs, effectively integrated the new acquisitions and achieved record production levels for the partnership. I’d like to start with the results at the partnership level and then discuss some of the details by division.

During in the fourth quarter, we produced 2.21 million barrels of oil equivalent, compared to 2.17 million barrels of oil equivalent in the third quarter. The increase in production was primarily a result of increased development activity and the Belridge acquisition that was completed during the fourth quarter.

We were pleased to see production for the full year of 2012 increase 18% from 2011 to approximately 8.32 million barrels of oil equivalent or about 22,700 barrels of oil equivalent per day. We’re at the year end 2012 exit rate of approximately 25,000 barrels of oil equivalent per day.

Additionally, fourth quarter 2012 production grew 11% compared to the first quarter of 2012. However, production was lower than forecasted for the quarter, primarily due to third-party infrastructure downtime and deferred well work in our Northern Division and lower than expected production from some of our Texas properties due to gas curtailment.

I will go into more details about this in just a moment. Our overall production split for the year was approximately 44% crude oil and NGLs and 56% natural gas.

Lease operating expenses and processing fees for the fourth quarter, excluding production and property taxes were $41.8 million or $18.88 per Boe. Full year 2012 lease operating expenses came in at $159.3 million or $19.15 per Boe. This is a little more than 1% lower than 2011 operating expenses of $19.39 per Boe.

During the fourth quarter, our cost of materials and services stayed relatively flat and for the whole year cost of materials and services increased 5% to 10%. As we discussed in the past, our cost were very much influenced by commodity prices and with continued strong oil prices during the year, we’ve seen upward pressure on costs.

In 2013, we will continue to keep a very sharp focus on managing costs across all of our properties. It’s one of our key metrics and it gets a lot of attention by our operating group. Total oil and gas expenditures in the fourth quarter were about $60 million and were $153 million for the full year.

Capital expenditures were significantly higher than $75 million spend in 2011 due to increased drilling activity in both our legacy assets as well as our assets that were acquired during 2012. Recall that during 2012, we had three consecutive increases to our capital program to fund additional opportunities identified on our legacy and newly acquired assets. In 2013, we expect to continue to expand our robust oil drilling program.

Let me provide you with an update on our year-end results and then I’ll go into some more detail on our operating results. As of December 31st, 2012, our total estimated crude oil and gas reserves were 149.4 million barrels of oil equivalent. This compares to year end 2011 reserves of 151.1 million barrels of oil equivalent.

The change in crude reserves was a combination of 33.7 barrels of oil equivalent of primarily oil acquisitions, 8.3 million barrels of oil equivalent of production that was balanced between oil and gas and 163 Bcf of downward revisions, that were almost exclusively to gas reserves. The downward revisions were essentially all due to the lower SEC gas price at year-end 2012, which was $2.76 per MMBtu compared to the 2011 year-end SEC price of $4.12 per MMBtu.

Our year-end 2012 reserves consisted of about 49% oil, 47% natural gas and 4% NGLs. And 80% of our crude reserves were classified as crude developed. Our 2012 acquisitions and the development programs in our legacy assets have increased our PUD percentage from 13% at year-end 2011 to 20% at year 2012, virtually all of the new PUD locations or oil locations, so all development opportunities continue to grow.

Standardized measure of future net cash flows from these reserves discounted at 10% is approximately $2 billion using SEC pricing and cost effective for the year-end 2012 calculations. Of the total estimated crude reserves, 35% were located in Michigan, 26% in Wyoming, 17% in California, 15% in Texas and 7% in Florida, with less than 1% in Indiana and Kentucky. And as Hal mentioned earlier, oil percentage of our reserves has grown from 35% to 53% over the last year.

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

However, production during the quarter was less than forecast mainly due to two issues. First, there was a significant amount of downtime from third-party plan and pipeline repairs in both Michigan and Wyoming. Second, there were more than 100 low-volume gas wells that we are shutting, due to being uneconomic to repair and return to production at current gas prices.

As gas prices improve, these wells will be repaired and put back on production. The combination of these two issues reduced net production by more than 1.6 million cubic feet a day equivalent. Fourth quarter per unit controllable lease operating expenses for the Northern Division were a $1.88 per Mcfe.

Capital spending in the Northern Division for the fourth quarter totaled approximately $17.9 million and consisted of 17 drill wells, 17 workovers and two facility optimization projects. Capital activity for this quarter was successful in adding incremental net production of about 650 barrels of oil equivalent per day. For the capital program, both cost and production came in a little bit better than forecast.

In the Southern Division, which includes California, Florida and Texas, fourth quarter production was 666,000 barrels of oil equivalent, which was up about 8% compared to third-quarter 2012 production and was up almost 50% compared to second quarter production. This increase was primarily due to the new acquisitions -- new development on those acquisitions and additional drilling in the Santa Fe Springs Field in California.

We had strong production growth despite losing approximately 250 net barrels of oil per day, due to curtailments on a portion of the gas gathering system in Texas. The system operator expects to have the system capacity expanded by third quarter of this year. So it’s not a quick solution but the issue is being addressed.

Controllable lease operating expenses for the quarter averaged $29.93 per BOE, which is about 2% lower than last quarter and 30% lower than Q2, due mainly to the acquisition of the new properties in Texas, which have lower LOE and also due to lower facility and infrastructure expense in California.

Capital spending in the Southern Division for the fourth quarter totaled approximately $41 million, which was above third quarter expenditures of $32 million, mainly due to the drilling activity in California, Florida and Texas.

During the quarter, 7 oil wells were drilled and completed in California, 10 wells were drilled in Texas, 5 of which have been completed by the end of the quarter and one well is drilled and completed in Florida. These new drilled wells added incremental net production of about 1,100 barrels of oil equivalent per day.

On January 1, 2013, BreitBurn assumed operations of the Permian properties we acquired in the first CrownQuest acquisition, and we will take over the operations of the second set of CrownQuest properties by May 1st of this year. There were two to three rigs operating on these properties during the fourth quarter, a total of 18 wells we’ll put on production in the second half of the year on the CrownQuest properties and five wells were either drilled or waiting on completion at the end of the year.

Project performances, as we projected during the acquisition process with the exception of the curtailment that I mentioned earlier. The curtailment only affects a portion of our properties, so until that problem is resolved we will continue to focus activity in the areas that are not restricted.

Turning to 2013, I want to spend a little bit of time discussing our capital program for each state. As Hal mentioned, 2013 will be a very active year for us. We expect to have full-year 2013 oil and gas capital program to be approximately $260 million. This does not include capital for new acquisitions. This is a significant increase from 2012 levels of approximately $153 million, due to the additional development opportunities we have in the properties we recently acquired. And also due to the opportunities, we continued to develop on our legacy properties.

Our 2013 program will focus on all projects, with about 99% of our discretionary capital and approximately 97% of total capital spent on all projects. We are forecasting 2013 production to be between 9.5 million and 10.1 million barrels of oil equivalent. For the December 2013 exit rate between 27,700 and 28,850 barrels of oil equivalent per day.

If we achieve the mid-point exit rate for 2013, it will be an increase of about 13% compared to the December 2012 average production rate. Of the $260 million in capital, we anticipate spending approximately $96 million in Texas, $84 million in California, $40 million in Florida, $27 million in Wyoming and the remaining $13 million in Michigan.

We plan to drill approximately 135 wells. Drilling costs will be about 80% or 85% of our total capital spending. From the 135 wells we plan to drill, 60 are expected to be in Texas, 46 in California, 18 in Wyoming, 7 in Michigan and 4 in Florida. Texas drilling program is forecasted to use three rigs continuously for the full year. These wells cost about $2.1 million each, and 30-day IPs are over 70 barrels of oil equivalent per day net.

In California, the sub service team working Sante Fe Springs has done an excellent job in identifying additional drilling prospects in the field that is more than 90-years old. Prior to 2012, we typically drilled 45 wells per year. During 2012, we drilled 20 wells with excellent results, average IPs were over 40 barrels oil equivalent per day.

We have recently acquired additional acreage within the field boundaries, approximately 30 acres of minerals and 45 acres of surface that gives us additional drilling targets in an area of the field that has not produce in over 20 years. In addition, we are utilizing a recently acquired 3-D seismic survey to further develop or to further help in identifying drillable locations. We expect to have one rig drilling continuously throughout 2013, and believe that a one-rig program can be sustained for the next four to five years. The Santa Fe Springs wells cost about $1.8 million each.

Elsewhere in California, we are planning to have one rig drilling for about four months in the newly acquired Belridge Field that will drill about 20 wells. The Belridge wells cost about $800,000 each, and the IPs are expected to be about 25 barrels oil equivalent per day.

We are continuing our Florida drilling program with four wells planned for 2013. Well costs are about $9 million per well and IPs averaged over 130 barrels of oil equivalent per day. In Wyoming and Michigan, we plan to continue to build on the success from the 2012 work program by infill drilling, primarily in our newly acquired oil fields in Wyoming.

2013 will be the same as other years for the operations’ team in terms of striving to operate efficiently and control costs. These will continue to be a strong focus for us. We plan to continue to evaluate project economics for oil and gas opportunities, as commodity prices change over the course of the year and we will allocate our capital to the projects that provide the best return for the company.

With that, I will turn the call over to Jim.

Jim Jackson

Thank you, Mark. I will start by reviewing selective results for the quarter and the year, and conclude with commentary on highlights on our 2013 guidance.

Adjusted EBITDA for the fourth quarter of 2012 was approximately $78 million and represented an increase of approximately 21% from the fourth quarter of 2011. While, fourth-quarter adjusted EBITDA was up year-over-year, it was lower than the prior quarter, principally due to the size and timing of our oil shipments in Florida. For the year, we are pleased to report adjusted EBITDA of $295.8 million, which represented a 31% increase from 2011 and a record for the Partnership as Hal mentioned.

Turning to earnings, we recorded a net loss of approximately $10.3 million or $0.13 per diluted common unit for the fourth quarter of 2012, as compared to a net loss of $73 million or $1 per diluted common unit in the prior quarter. The decrease was primarily due to lower unrealized losses on commodity derivative instruments as compared to the prior quarter.

For the full year 2012, we recorded a net loss of approximately $40.8 million or $0.56 per diluted common unit compared to a net gain of $110.5 million or $1.79 per diluted common unit in 2011. The decrease was primarily due to unrealized losses on commodity derivative instruments due to higher crude oil prices.

As you know, we are required under GAAP to mark-to-market our commodity derivative portfolio every reporting period. Unrealized gains or losses in commodity derivative instruments are non-cash items that do not impact our adjusted EBITDA or distributable cash flow. Excluding these unrealized losses, we would have had adjusted net income of $8.4 million during the fourth quarter and $41.2 million for the full year.

We reported total oil and gas capital expenditures in the fourth quarter of $60 million, up from $49 million in the third quarter due to the capital program increase in November, which was focused on our California oil assets.

For full year 2012, total oil and gas capital expenditures were $153 million, up from $75 million in 2011. We doubled our capital expenditures during the year as a result of increase drilling activity on our legacy assets and recently acquired properties.

Cash interest expense for the fourth quarter and full year 2012, including the impact of realized losses on interest rate derivative but excluding the loss on termination of an interest rate swap were $17.4 million and $59.4 million, respectively. These amounts compared to third quarter 2012 and full year 2011 total of $15.2 million and $37.8 million, respectively.

Now I’d like to discuss distributable cash flow for the fourth quarter and full year 2012. Distributable cash flow was approximately $44 million in the fourth quarter. This amount reflects adjusted EBITDA of $79.3 million, which is adjusted from the reported $78 million number to exclude a one-time executive departure payment totaling approximately $1.3 million, less cash interest expense of $17.4 million, as I’ve described earlier, less assuming its capital of approximately $16.8 million.

On a per unit basis, distributable cash flow was approximately $0.51 per unit. Our coverage ratio for the quarter based on $0.47 distribution which was paid on February 14th was 1.08 times.

For the full year ended 2012 or for full year 2012, excuse me, based on adjusted EBITDA, cash interest expense as discussed and maintenance capital of approximately $67 million, our distributable cash flow was $170.8 million and a coverage ratio based on full year distributions of $1.85 per unit was 1.18 times.

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 fourth quarter averaged $6.14 per Mcf, compared with Henry Hub natural gas spot prices of $3.40 per Mcf.

On the oil side, average realized crude oil and liquids prices were $91.38 per barrel, compared to NYMEX crude oil spot prices of approximately $88.01 per barrel for the same period.

Brent crude oil crude oil spot prices which are an important benchmark for our California oil production averaged $110.15 per barrel in the fourth quarter of 2012, compared to $109.63 in the third quarter 2012.

We are pleased to announce that in the last four months we have significantly increased our oil hedge portfolio by over 40% and total hedge portfolio by over 26%. Since November, we have added hedges on approximately 3.4 million barrels of oil production for the period covering 2013 through 2017 at an average price of $95.22 per barrel and approximately 6.6 Bcf of natural gas production for the period covering 2013 through 2017 at an average price of $4.20 per MMBtu.

Assuming the midpoint of our 2013 production guidance is held flat, our production is hedged 77% in 2013, 74% in 2014, 68% in 2015, 38% in 2016 and 10% in 2017. Average annual prices during this period range between $88.20 and $95.61 per barrel for oil, and $4.30 and $5.87 per MMBtu for gas. Our hedge book consist principally of swaps and costless collars which makeup approximately 95% of our total hedge volumes.

We expect to add additional oil and gas hedges in years 2013 to 2017 in the months ahead, and we’ll continue our practice of hedging acquisition very aggressively. An updated presentation of the Partnership’s commodity price protection portfolio will be made available in the Events and Presentation section of our Investor Relations tab on our website later today.

Now I’d like to review our financing activities for 2012. During 2012 we completed two equity offerings one in February and one in September where the Partnership issued 9.2 million common units priced at $18.80 per unit and 11.5 million common units priced at $18.51 per unit, respectively.

In addition, the Partnership issued $250 million of [7 and 7/8s percent] senior notes due 2020 in January of 2012 and issued an additional 200 million of those same notes in September.

In total financing activities in 2012 raised approximately $820 million in net proceeds, which were used to reduce the borrowings under our credit facility that we incurred to fund acquisitions.

As you know, our acquisitions are initially funded by borrowing on our credit facility, we then access the debt and equity markets opportunistically overtime to repay the amounts and position us for further acquisition activity.

While long-term debt and equity are more expensive than short-term back debt it is important for us to have a stable and secure balance sheet to fund our assets long-term, and also have significant financial flexibility to fund our growth through acquisition strategy and increase distributable cash flow per unit.

Turning to our recent financing activities, earlier this month we completed a very successful offering of 14.95 million common units at a price to the public of $19.86 per unit. I’d like to point out that this price was in excess of the price we achieved in the previous two equity offerings completed in 2012.

We access the equity market opportunistically under favorable market conditions and we’re very pleased with the results and the market receptiveness to our offer. Prior to the transaction, we had approximately $334 million in outstanding borrowings under our credit facility, which were primarily used to fund our recent Texas and California acquisitions.

As I have said before, we have a disciplined financial policy, which includes maintaining a conservative leverage profile as measured by the ratio of total debt divided by last 12 months pro forma adjusted EBITDA of between 2.5 and 3.021.

We often exceed this range for some period of time following acquisition but then work to bring our leverage metrics back in line with our target levels over time. As of today, we have only $77 million drawn on our credit facility with a borrowing base of up to $1 billion and a debt-to-pro forma last 12 months EBITDA ratio of just under 2.5 times. Our financing strategy continues to afford us considerable financial flexibility to pursue opportunities for further growth.

Before I move onto our 2013 guidance, I have one last comment to make on our last equity offering. Due to the timing of the offering on the same day as our ex dividend date which was February 7th, many investors thought that purchasers of the new units were entitled to receive fourth quarter distributions.

I’d like to clarify that that was not case since the offering was priced after the close of trading on the ex-dividend date. Investors in our recent offering will receive their first distribution payment in May of this year.

Now, we will review 2013 guidance, which was announced in the press release we issued earlier this morning. As Hal and Mark mentioned, excluding acquisitions, we are projecting production for 2013 to be between 9.5 million and 10.1 million BOE. This guidance reflects reduced drilling activities on our gas properties due to continued depressed natural gas prices.

Our December 2013 exit rate is projected to be 27,700 Boe per day to 28,850 Boe per day. We project our production mix to be 53% oil and 47% gas for the year, in addition, approximately 30% of total oil productions.

Total capital expenditures excluding any 2013 acquisition are planned to be between $253 million and $263 million. And this includes estimated maintenance capital of $75 million plus growth capital expenditures of between $178 million and $188 million.

Our operations team will continue to focus on controlling costs in 2013. We expect 2013 operating cost to be between $18.25 and $20.25 per Boe. These estimated operating costs include lease operating expenses, processing fees and transportation expense.

Expected transportation expense totals approximately $6.7 million in 2013 largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs per Boe are expected to range between $17.58 and $19.58 per Boe.

When estimating operating costs for 2013, we are assuming flat $95 per barrel WTI crude oil pricing, $105 per barrel Brent crude oil pricing and $3.50 per Mcf for gas price levels. Production taxes are expected to range between 7.5% and 8% of oil and gas revenues.

Regarding general and administrative expenses, for 2013, excluding unit-based compensation, we expect these expenses to range between $33 million and $35 million for the year or approximately $3.47 per Boe based on the midpoint of our production guidance range.

The partnership expects to generate adjusted EBITDA and non-GAAP measure of between $330 million and $340 million in 2013. This range is based on the number of operating and other assumptions, including commodity prices remaining at or near the oil and gas price levels mentioned earlier and reflect the benefits of the partnerships of the existing hedge portfolio.

We’re forecasting cash interest expense of between $69 million and $71 million, which reflects interest on both our expected bank borrowings before any acquisition and our existing senior notes. The interest expense on the bank credit facility assumes one month LIBOR rate of 30 basis points plus the applicable LIBOR margin as per our credit agreement.

In 2013, we expect production, adjusted EBITDA and distributable cash flow to increase throughout the year quarter to quarter.

In conclusion, I’d like to reiterate that 2012 was an outstanding year on many fronts. Our asset base and organic growth opportunities have grown considerably with our acquisitions. We see there are acquisition target goal and achieve record production and adjusted EBITDA.

Furthermore, with our highly successful financing activities, we are starting the year with a very strong balance sheet that positions us to capitalize on the growth opportunities we see in 2013. We look forward to another great year and we thank our unit holders for their continued support.

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

Question-and-Answer Session

Operator

(Operator Instructions) And your first question will come from Ethan Bellamy with Baird.

Ethan Bellamy - Baird

Good morning, everybody. I’ll go east to west. So in Florida, volatility in crude oil shipments for ‘13, anything we should be looking for there?

Mark Pease

Hi. This is Mark. Now, I mean, it’s typically in their periodic but it looks like we’ll have about six shipments in 2013. We did have some inventory at the end of 2012. And you probably noticed that until we had about 70,000 barrels in inventory but nothing unusual for ‘13.

Ethan Bellamy - Baird

Okay. What’s the latest on cross activity in Michigan, Collingwood-Utica?

Mark Pease

Really no change. Ethan, I mean, when we’ve -- as we’ve said before, we think it has potential, that’s not really our ball game. Essentially all of our acreage and we have over 130,000 acres that we believe prospected for that, is held by production. So we’re watching what the other companies were doing.

In Kansas, still out they are doing some more contesting and so a couple other companies but we’re watching that but no significant change to that.

Ethan Bellamy - Baird

Nobody showed up of basking the firm and/or something like that?

Mark Pease

Not yet.

Ethan Bellamy - Baird

Not yet. Okay. So in California, anything troublesome from -- or more troublesome than normal from a tax and regulatory perspective at the state level?

Hal Washburn

Ethan, this is Hal. No, not really. I mean California is California but we continue to monitor to it. We are very active in the trade association and nothing unusual. Nothing more than what we normally deal with.

Ethan Bellamy - Baird

Okay.

Mark Pease

I will say then we have actually seen it get a little bit better over the last couple of years.

Ethan Bellamy - Baird

Okay. The Linn Berry deal, did that shake anything up in the California landscape?

Hal Washburn

Probably not, Berry has been producing California for some thing like 100 years. And Linn has been in California since almost the beginning of their -- since they were formed in ‘06. So we don’t expect to see a lot of changes there.

Ethan Bellamy - Baird

Okay. Last thing, and for Jim, your maintenance CapEx guidance. Is that reserve replacement, production replacement or cash flow replacement and should we just assume 23% of EBITDA every quarter for the year, or is there any lumpiness in there we should look for?

Jim Jackson

Yeah. Ethan, it is Jim. That is based on our detailed review. The amount of capital we’ve been able to take during the year to hold production flat. And it does work out to about 23% of EBITDA and there isn’t really anything from quarter-to-quarter that’s unique about it. So, I think if you were to assume that I could spend evenly throughout the year you’ll be fine.

Ethan Bellamy - Baird

Helpful. Thanks and congrats on a good year.

Hal Washburn

Thank you.

Jim Jackson

Thanks, Ethan.

Operator

And from Raymond James, we will go to Kevin Smith.

Kevin Smith - Raymond James

Hi. Good afternoon, gentlemen.

Hal Washburn

Kevin.

Kevin Smith - Raymond James

Yeah. Two real quick questions. Mark, does that 25,000 barrel a day exit rate, does that include your two acquisitions? I know you had some stuff closing right at year-end.

Mark Pease

We did, but that’s actually our average December, right. Kevin, so it includes that but there is not much volume in there for you.

Kevin Smith - Raymond James

Okay. Perfect. Thanks. And then, is there any CapEx associated with bringing those 250 BOE of production that shutting in taxes is back on? I would imagine there is not a very minimal.

Hal Washburn

There is not. It’s all the pipeline company that they do require CapEx to expand their system but it doesn’t impact us.

Kevin Smith - Raymond James

Okay. And then just lastly, any thoughts about when you would expect to place those Michigan gas wells back online? Is there any kind of STRIP curves you need to see?

Hal Washburn

They all are little bit different because it depends on what we need to do to them. Fortunately, there aren’t leases that are held by production. So it’s not an issue of leasing reserves. But if we can get gas sustainable up in sort of a close to $4 range, $3.50-$4 range and I think we could get most of those back on production.

Kevin Smith - Raymond James

Okay. That’s all I have. Thanks.

Hal Washburn

Welcome.

Operator

(Operator Instructions) We’ll hear from Praneeth Satish with Wells Fargo.

Praneeth Satish - Wells Fargo

Hey. Good afternoon. Just a couple of quick questions for me. One of your peers has hedged out their crude basis exposure in the Permian for the balance of the year. Is that something that you guys look at or considered doing?

Hal Washburn

Yeah. We’ve looked at that and we’ve looked a lot of basis. At this point, we haven’t entered into any. We do hedge our gas directly in some cases to Michigan and others. But at this point, we are not. We are not doing that but we are looking at entering that market. We haven’t entered into trade at this point.

Praneeth Satish - Wells Fargo

Okay. And I appreciate the guidance around the 2013 exit rate production. Just wondering if you could break out how much of your production you expect to be liquids versus gas at the end of this year?

Hal Washburn

We haven’t -- I suppose that Mark, do you have those numbers available?

Mark Pease

We can get them. It will take us some effort. I don’t have that right here. We exit the year right at 50-50, 2012 and we set the 2013 production is going to be I think 53-47. So, if doing the quick math, I would say that we are mid-to-high 50s oil going out of the year. But let’s us do a little bit of checking on that number.

Praneeth Satish - Wells Fargo

Okay.

Hal Washburn

As we said earlier, virtually all of our capital is going to be spend in our oil properties this year. So you would expect to see growth there and we will see the natural decline in the gas properties and will continue.

Jim Jackson

Hey, Praneeth, it’s Jim. I have it for the year. Fourth quarter gas production will make up 45% plus or minus 1% of total production. So, yeah, Mark is right on 55-45 basically in the fourth quarter or thereabout.

Praneeth Satish - Wells Fargo

That’s helpful. Thanks. Just one last question for me. Do you have a break-even oil price that would cause you to scale back some of that CapEx spending for ‘13?

Hal Washburn

Yeah. We do, Praneeth, but it’s low. I mean it’s a little bit different for each area. But Florida would probably be the first area that would be impacted and we would have to get below $80 a barrel for that and the others are lower than that.

Praneeth Satish - Wells Fargo

Okay. Got it. Thanks a lot.

Hal Washburn

You bet.

Mark Pease

Thank you.

Jim Jackson

Thanks, Praneeth.

Operator

And we’ll take question from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Hello.

Hal Washburn

Hello. How are you?

Noel Parks - Ladenburg Thalmann

Good. Thanks. Just a few things. With your most recent acquisition in Texas, I assume some of the capital for this year is going to work in those properties. Just talk a little bit about just what the new development opportunity is there in that most recent set of acquisitions there?

Hal Washburn

Sure, we can. It’s the new set of properties in Texas are -- in fact, some of them overlap with the first CrownQuest acquisition we did. It was buying additional interest in the same wells and some of them are in the very same area. So it’s all Wolfberry play. So it’s very, very similar. Some are exactly the same as what we did with first CrownQuest acquisition.

Noel Parks - Ladenburg Thalmann

Got it. And actually, what sort of spacing ultimately could you had toed out there?

Hal Washburn

It’s a great question. The area that we are in right now and what our current plans are take us down to 40 acre spacing and that’s how we would value these properties. But there is a lot of work going on, not very far from us down to 20 acres. So we are not planning on 20s and we didn’t pay for 20s. But I will be surprise that ultimately we don’t get on smaller spacing than 40s.

Noel Parks - Ladenburg Thalmann

Great. I mean, what sort of timeframe would you be looking at that, if that would be the opportunity sort of at your current drilling place? Are we talking a couple years out maybe or…?

Hal Washburn

Yeah. I think what you will see us do is, we’ve got a couple of years of drilling just to get everything down to 40s and probably at some point during that time, we will test some wells at 20s to see what they do. We certainly won’t wait until we drill all our 40s before we test the 20s idea. But it will be a couple years before you see us drilling. I mean, if going to 20s is economic, it will be a couple years before you see us doing a lot of work on 20s.

Noel Parks - Ladenburg Thalmann

Great. And sort of along the lines of one of the previous questions. In the Wolfberry, what sort of oil do you need to be comfortable investing there?

Hal Washburn

Dollars per barrel?

Noel Parks - Ladenburg Thalmann

Yeah.

Hal Washburn

Substantially below 80.

Noel Parks - Ladenburg Thalmann

I was just wondering because during sort of the ‘09 crash period, I know there were some operators who scaled back in Wolfberry and there were of course some other parts of the Permian.

Hal Washburn

We are still good to 70. And it’s somewhere south of 70.

Noel Parks - Ladenburg Thalmann

Okay. Great. And thinking of the infrastructure issues that you had in fourth quarter, I know there were a few in third quarter as well. Is basically infrastructure downtime your biggest operational risk at this point?

Hal Washburn

Yeah. I think so. I mean, we are a new operator out there and if you’ve listen to our previous calls we talked a lot about the relationship with CrownQuest. We just took over operations on the producing oils on January 1st. CrownQuest is a very good operator. They’ve been very cooperative with us. We’ve got a very good working relationship with them.

As you can probably tell by the second acquisition we did with them. And so we are learning a lot from them. So if we had gone out there cold turkey, didn’t know anything about there area and went with the strong operator. I’d be answering that differently. But I think right now just making sure we have takeaway capacity for our natural gas is key.

Noel Parks - Ladenburg Thalmann

Got you. And I mean, is activity sort of new plays in and about that area from other operators who were sort of more at exploratory mode? Does that put any significant pressure on your infrastructure assets you think over next couple of years or so?

Hal Washburn

Yeah. I don’t think it’s much exploration, I mean, this continued very strong development effort going on out there and our job is going to be to plan and stay ahead of that to make sure that we can minimize any constrains we have.

As for as additional exploration, I don’t know that there’s a lot of additional exploration going on in that same area, the exploratory ideas are more about how tight can you take the spacing in the Wolfberry. What’s the best completion type to use? Those type of things. So it’s not so much new formation just more about how you complete them and produce them.

Noel Parks - Ladenburg Thalmann

Great. That’s all for me. Thanks a lot.

Operator

(Operator instruction) We’ll take a question from Michael Peterson with MLV & Co.

Michael Peterson - MLV & Co.

Good day, everyone. I have two questions. First one regards PUD share of your proven reserves? Are you now where you want to be in terms of your PUD component of the portfolio or would assets like the Belridge Field be relatively more attractive in 2013?

Hal Washburn

We like where we are right now but we took a very large write-down on our gas PUDs. We have done big chunk of those. So if gas prices were to rebound, we would just naturally pick up a lot of gas drilling which we set for a long time, something we like the auction value in.

I don’t think you are going to see us getting to 30% or 40% PUD, unless we were able to make an acquisition with a lot of undeveloped reserves that we didn’t pay anything for it. Those sorts of deals do come along occasionally, but we’re not seeing a much of them right now, at least not in oil.

Michael Peterson - MLV & Co.

Okay. So the 20% gives you enough forward visibility and installation if you will from changes in the M&A market that you feel comfortable with?

Hal Washburn

Yeah. It is, we think it’s important, wouldn’t heard to be slightly higher, but I think that’s good number where we are right now.

Michael Peterson - MLV & Co.

Okay. Terrific. Next question with regards to what is a very enviable liquidity position. I think that probably reflects what you’ve detailed as a positive outlook on the asset market. Can you share with us a little bit of perspective on how the M&A market looks both relative to last year and in particular relative to the fourth quarter in terms of both prices and asset volumes on offer?

Hal Washburn

Sure. Well, the fourth quarter was a record quarter. It was driven by a lot of concern about what 2000 would bring in the form of tax increases, probably…

Michael Peterson - MLV & Co.

Sure.

Hal Washburn

… concern that was, probably concern turned out to be justify. So we benefited greatly, did a number of transactions at the end of the year that were driven by those concerns. We expect to 2013 to be very strong.

I think the first quarter is a little bit slower, although, we’ve just seen some deals announced by our peers. So there’s a lot out there. We’ve screened a number of deals so far this year and are very optimistic that we got a robust market continuing on in ‘13.

There are lot of deals that got -- that went on the market at the end of ‘12 that didn’t get done, and so lot momentum from those transactions I believe to continue on in ‘13. As far as pricing, it’s too early to tell on the transactions. I think that, I don’t anticipate the significant changes either up or down on the asset values and asset prices at this point.

Michael Peterson - MLV & Co.

Color is helpful. Thank you. That’s all I have.

Hal Washburn

Okay.

Mark Pease

Thanks Michael.

Operator

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

Hal Washburn

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.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: BreitBurn's CEO Discusses Q4 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts