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

Q4 2013 Earnings Conference Call

February 27, 2014 12:00 PM ET

Executives

Greg Brown - EVP, General Counsel and CAO

Hal Washburn - CEO

Mark Pease - President and COO

Jim Jackson - CFO

Analyst

Noel Parks - Ladenburg Thalmann

John Ragozzino - RBC Capital Markets

Praneeth Satish - Wells Fargo Securities

Michael Peterson - MLV & Company

Doug Christopher - Crowell Weedon & Company

Operator

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 on its website at www.breitburn.com. During the presentation, our participants will be in a listen-only mode. Afterwards, securities analysts and institutional portfolio managers will be invited to participate in a question-and-answer session. (Operator Instructions) As a reminder this call is being recorded February 27, 2014.

A replay of the call will be accessible until midnight Thursday, March 6th, by dialing 877-870-5176 and entering conference ID 7789996. 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

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

Let me remind you that today's conference call contains forward-looking statements within the meaning of the federal securities laws. All statements other than statements of historical facts that address future activities and outcomes are forward-looking statements. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ materially from those expressed or implied in such statements. These forward-looking statements are our best estimates today and are based upon our current expectations and assumptions about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change from those we projected over the course of the year.

A detailed discussion of many of these uncertainties are set forth in the cautionary statement relative to forward-looking information section of today’s release and under the heading Risk Factors incorporated by reference from our Annual Report on Form 10-K currently on file for the year ended December 31, 2012, and our quarterly reports on Form 10-Q, our current reports on Form 8-K and our other filings with the Securities and Exchange Commission. Our Form 10-K for the year ended December 31, 2013 is planned to be filed tomorrow. 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, and distributable cash flow which are non-GAAP financial measures and are reconciled to their most directly comparable GAAP measures in our earnings press release issued this morning. Management believes that these non-GAAP financial measures enhance comparability to prior periods. Adjusted EBITDA is presented as management believes it provides additional information relative to the performance of the Partnership's business such as our ability to meet our debt covenant compliance test.

Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-GAAP financial measures may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies, because all companies may not calculate adjusted EBITDA or distributable cash flow in the same manner.

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

Hal Washburn

Thanks, Greg. Welcome everyone and thank you for joining us today to discuss our fourth quarter and full year 2013 results. We began the year with clear objectives for growth on two fronts; expand our asset base through oil weighted acquisitions and accelerate the development of our oil legacy assets with a first strong capital program. We’re very pleased to have delivered on these objectives by completing approximately $1.2 billion in acquisitions, which not only significantly increased our scale, but also increased the liquids component of our year-end total estimated reserves to 60% versus 35% liquids at year-end 2011.

We also executed on a very large capital program totaling $295 million, the largest in the Partnership’s history to focus on attractive high margin oil projects that were identified principally in our Texas, California and Oklahoma properties. While we experienced some operating, pricing, weather and CO2 supply challenges in the fourth quarter, we grew the business significantly in 2013 and are pleased to report record annual production and adjusted EBITDA for the year.

Production for 2013 was approximately 11 million Boe, an increase of 32% from 2012 and the highest yearly production in BreitBurn’s history. Adjusted EBITDA for the year was approximately $370 million, an increase of 34% from 2012 and another record high for the Partnership. In 2013, we also delivered on our commitment to provide consistent distribution growth to our unitholders. Annualized monthly distributions of a $1.97 per unit attributable to the fourth quarter of 2013 represent a 4.8% increase over annualized quarterly distributions for the fourth quarter of 2012.

As you may recall, we converted to a monthly distribution payment policy in January of 2014. This change was made based on investor feedback and is designed to more efficiently return capital to investors and satisfy the growing demand for investments paying monthly distributions.

Now I’d like to briefly review our 2013 acquisition activity. We had a target of at least 500 million in acquisitions for the year and we significantly surpassed that by completing two major transactions along with 9 smaller deals totaling approximately $1.2 billion. First in July, we completed the Postle acquisition for approximately $845 million plus additional interest in other assets in the Oklahoma Panhandle for an additional $30 million. The acquisition included the Postle field and the Northeast Hardesty unit both of which are located in Texas County, Oklahoma. The fields are matured legacy oil fields that have large amounts of original oil in place, very predictable production, low decline rates, low risk development inventories and low maintenance capital requirements. We have contracted supply of CO2 from the Bravo Dome field in New Mexico with step-in rights for approximately 140 Bcf over 10 to 15 years which when combined with recycled CO2, we expect will be more than sufficient to produce our estimated total reserves.

Total estimated proved reserves in the Oklahoma properties were as 43.6 million Boe at year-end 2013. As part of the acquisition and the purchase of additional interest we also became the sole owner of the Dry Trails gas plant located in Texas County, Oklahoma and the 120 mile pipeline Transpetco Pipeline, a CO2 transportation pipeline delivering product from New Mexico to the Postle field in Oklahoma. We are very pleased to enter into the Mid-Continent with high quality oil properties and strategic midstream assets to support our current and future CO2 needs. We are very focused on expanding our presence in the Mid-Continent and are closely monitoring new opportunities that fit our business model.

We completed a second significant acquisition on December 30th, of additional Permian Basin properties for approximately 300 million from CrownRock LP and other minority sellers. This was the third CrownRock acquisition since May of 2012. It’s a bolt-on deal that further expands our Permian Basin presence. The properties have estimated proved reserves of 18.4 million barrels and include about 100 producing wells. Our total drilling locations in West Texas are now 250 locations with 40 acre spacing and 450 locations on 20 acres. The CrownRock acquisition provided us with new interest in additional oil and gas properties adjacent to our existing operations, as well as incremental interest in oil and gas properties that we already owned and operated.

Combined the Postle and CrownRock acquisition significantly expanded our operations, our liquids reserves and liquids production. In total the acquired assets increased total proved reserves by approximately 62 million Boe and added over 10,000 Boe per day of average daily liquids production. As I’ve mentioned earlier, our key objective last year was to continue transforming our portfolio more towards liquids. We are pleased to announce with last year’s acquisitions, our total 2013 estimated proved reserves comprise 53% oil, 7% NGLs and 40% nat gas. This represents a 13% increase in liquids as a percentage of total estimated proved reserves in 2012.

Furthermore, with the combined effects of our capital program, which focused on oil projects, fourth quarter 2013 liquids production increased 90% from fourth quarter 2012. Consistent with our 25 year history, we were a selective and disciplined acquirer in 2013.

Now I’d like to touch on our capital program for 2014. This year our oil and gas capital expected spending will be between 325 million and 345 million, focused principally on our oil assets in Texas, California and Oklahoma. We plan to drill or re-drill 168 gross wells in 5 states and plan to have 4 continuous drilling programs with up to 6 rigs running during the year. Mark will go over our capital program in detail later on.

For 2014, we are projecting total production between 13.6 million and 14.4 million Boe before any acquisition. Note the midpoint of this range is approximately 217% higher than our 2013 total production. We project 2014 adjusted EBITDA before any acquisitions to be between $500 million and $510 million. The midpoint of which is approximately 36% higher than our 2013 total adjusted EBITDA. Jim will provide further details related to guidance later on in the call.

We are entering 2014 with a very strong asset base and a significant portfolio of organic growth opportunities. During the year, we are also targeting at least $600 million in acquisitions which along with our organic growth opportunities should support distribution growth.

Before I turn this over to Mark, I’d like to highlight the 2013 marked BreitBurn’s 25 year anniversary. We are very proud of our history. We started with just a few wells in California in 1988 and after 25 years of consistently operating and growing the business, we have become one of the leading upstream MLPs. For 25 years we have had one strategy, and that is to acquire long life assets with low risk exploitation and development opportunities and to excel as strong operators.

We’re convinced the singular vision, driven by responsible decision making will deliver long-term value to our unitholders. We thank our employees for their hard work and our investors for their continued support.

With that I’ll turn the call over to Mark, who will discuss our fourth quarter and full year operating results as well as our 2014 capital program in more detail. Mark?

Mark Pease

Thanks, Hal. I am pleased to see everything the Partnership has accomplished this year and certainly want to acknowledge the contributions of our strong operating team. We had a busy year executing on a very active capital program, integrating the Postle and Permian Basin acquisitions and optimizing operations across our properties. I would like to start with the results at the Partnership level and then discuss some of the key activities in more detail.

We completed 27 gross, 25.7 net drilled wells and nine workovers during the fourth quarter, which added total incremental net initial production of approximately 2,000 barrels of oil equivalent per day.

Production for the fourth quarter was relatively flat compared to the third quarter at 3.1 million barrels of oil equivalent. As Hal mentioned earlier, we had a handful of issues that laid on production this quarter. New well production timing, delayed completion of the Libby Ranch CO2 facility, difficult winter weather and downtime on a few key wells. I’ll go into further detail on these issues later in the call.

While we certainly had some challenges in the fourth quarter, for the second consecutive quarter we delivered record high liquids production. Fourth quarter liquids production was 1.9 million barrels of oil equivalent which represented a 90% increase compared to the fourth quarter of 2012. We expect to continue to see growth in liquids production in 2014, due to our emphasis on the higher margin oil projects across our portfolio.

For the full year 2013, we reported total net production of about 11 million barrels of oil equivalent which represented a 32% increase from 2012 and a record high for the partnership. However, full year production came in below forecast mainly due to the negative impact to production in the fourth quarter from the issues I just mentioned. Liquids production for the year accounted for 57% of total production, compared to 44% for 2012. As Hal mentioned earlier, we’re pleased to see the strategy driving our capital program and acquisitions for the past few years, expand our exposure to oil, it was one of our important goals.

We’re comfortable with the current commodity mix in our portfolio and as we have demonstrated before we will continue to manage our asset base very closely and deploy capital to those assets that provide the best return based on our current view on commodity prices. Lease operating expenses and processing fees for the fourth quarter excluding production and property taxes were $63.3 million or $20.56 per barrel of oil equivalent. This is about 8% higher than Q3 primarily due to the production issues previously mentioned and increased activity on our California assets.

Full year 2013 lease operating expenses came in at $216 million or $19.69 per Boe, about 2.8% higher than 2012 operating expenses of $19.15 per Boe. Our operating team managed costs well in 2013 particularly as it was a period of high growth and this is an area where will continue to be very focused in 2014.

Total oil and gas capital expenditures in the fourth quarter were about $96 million and were $295 million for the full year. 2013 capital expenditures almost doubled from 2012 levels due to increased drilling activity in Texas, California and Wyoming and due to the development of the newly acquired assets from Whiting.

For the full year we drilled 138 gross and 121.6 net wells and did 61 gross, 54.8 net recompletions, which added incremental net initial production of approximately 7,825 barrels of oil per day equivalent, a very solid accomplishment from our team. 2013 capital expenditures included approximately $235 million of projects that added incremental production during 2013, and approximately $60 million for CO2, CO2 facilities and the drilling of wells are expected to add production in future years.

Okay, let’s talk about where we finished the end of the year regarding our reserves. As of December 31, 2013 our total estimated proved reserves were 214.3 million barrels of oil equivalent. This compares to year-end 2012 reserves of 149.4 million barrels of oil equivalent. Change in proved reserves was primarily a combination of increases of approximately 64.8 million barrels of oil equivalent from acquisitions and 9.8 million barrels of oil equivalent and positive revisions to 2012 estimates, offset by a reduction of about 11 million barrels due to 2013 production. The upward revisions were essentially all due to higher SEC gas prices at year-end 2013, which were $3.67 per MMBtu compared to the 2012 year-end SEC price of $2.76 per MMBtu.

Our year-end 2013 reserves consisted of 53% oil, 40% natural gas and 7% NGLs, 81% of our proved reserves were classified as proved developed, standardized measure of future net cash flow from these reserves discounted at 10% is approximately $3.2 billion using SEC pricing and cost effective for year-end 2013 calculations, of our total estimated proved reserves 27% were located in Michigan, 20% in Oklahoma, 19% in Texas, 17% in Wyoming, 11% in California, 5% in Florida and less than 1% in Indiana and Kentucky.

Now let’s talk about some of our specific operating results. First let’s talk about California. Production for the fourth quarter came in at 438,000 barrels of oil equivalent which was slightly below our forecast due to our Santa Fe Springs wells being drilled deeper than originally planned. We’re finding good productivity deeper but the wells take longer to drill which results in fewer wells being brought online during the quarter. We also were limited on production due to facility constrains at both Santa Fe Springs and Belridge resulting from increased production from our drilling programs.

For the year net production for California was above forecast primarily due to the good results from the drilling programs at Santa Fe Springs and Belridge and acceleration of the Belridge field program relative to our initial estimate. Year-over-year California production was up 30% compared to 2012. Capital expenditures including capitalized engineering cost in California totaled $17 million for the fourth quarter and included 4 drilled wells and 4 workovers. In total, the capital activity for the quarter added incremental net initial production of about 470 barrels of oil equivalent per day which was above our predrilled expectations.

Facility work continues at Belridge and Santa Fe Springs as we’re designing the necessary infrastructure to handle the anticipated increase in future production. For both fields, this will consist of a new substation to deliver more electricity, continued increases in water handing capacity and increase in oil sales line capacity and increased gas handling capacity. California was one of the areas that was hit hard in the four quarter by widening oil differentials. The differentials to brand increased by more than $8 per barrel compared with the third quarter and by more than $10 per barrel compared to the average differential for the first three quarters of the year. We have seen the differential narrow by about $3 per barrel so far in 2014 that had a significant impact on our fourth quarter. California continues to be a key area of focus in our operating plan. The assets have responded very well to our work programs the last couple of years and we expect to remain very active here in 2014.

Now let’s move to Texas. Net production for the quarter came in at 369,000 barrels of oil equivalent which was below our forecast, but relatively flat compared to the prior quarter. Production was significantly impacted by the delay in reaching peak rate on our new drill wells and by downtime from severe winter weather in the region. On the new wells, we’re finding that it takes 2 to 3 months longer than originally forecast for the wells to clean up and reach peak production after they’ve been completed. As we have a very active drilling program, the increased time to peak rate impacted several wells hurting fourth quarter production by about 700 barrels of oil equivalent per day.

Additionally, severe winter weather in November and December caused freeze-offs and power outages that accounted for about 175 barrels of oil equivalent per day of lost production in the fourth quarter. So it was a difficult quarter for production in Texas but the weather issues are temporary and we’ve included a more accurate ramp-up for production from the new wells in our current models. Texas was another area where our differentials widened during the fourth quarter increasing by more than $2 per barrel compared with the third quarter. We did see the NGL differentials improve by about $11 per barrel compared to Q3. Texas NGLs comprised 2% to 3% of total company production.

Capital expenditures in Texas totaled 30.9 million for the quarter and included the drilling and completion of 15 new wells. In total, the capital activity for the quarter had an incremental net initial production of about 1,100 barrels of oil per day equivalent. During the quarter, we picked up another company operated rig and at year-end had two company-operated drilling rigs working.

Controllable LOE for the quarter in Texas was approximately $3.2 million or $8.57 per Boe, down from $10.09 per BOE in the third quarter. This makes Texas our lowest cost operating area. We also closed out third CrownQuest acquisition in December 2013 and are very pleased that the assets have already been integrated into our portfolio. As Hal mentioned earlier, this was a great bolt-on acquisition that gives us plenty of development opportunities to focus on in 2014.

Next I want to talk about our Oklahoma assets which we acquired mid last year. We assumed operations following the expiration of the transition services agreement with Whiting on October 31, 2013 and the transition went smoothly. We retained all of the field personnel which was very important and our technical team of 46 people worked side-by-side with the Whiting technical group in Midland for several weeks prior to taking over operations and the team is doing an excellent job operating the properties.

We did have some production challenges in the fourth quarter. Production for the quarter was 634,000 barrels of oil equivalent which was below forecast by about 600 barrels of oil equivalent per day principally due to a decrease in CO2 supply and injection. The Libby Ranch CO2 development project operated by Whiting through completion was initially scheduled to start operating in June of 2013 but was delayed several months and did not come online until November. This delay significantly impacted our CO2 supply and injection and ultimately the oil production.

We worked to address the gap in our CO2 supply by amending our contract with Exxon to supply Postle with an additional 10 million cubic feet per day of CO2 for 2014 starting January 1st and also added an additional 15 million cubic feet per day for 2015. We’re confident that our production will increase and we will not have any loss in reserves due to the delayed CO2 injections but it will take some months to ramp production back up. We have built this into our forward forecast.

Capital activity for the quarter totaled about $35.1 million and consisted of three drilled wells and the Libby Ranch CO2 project. Three drilled wells which consisted of two producers and one injector were successful coming on at budget for cost for both cost and rate. Now that the Libby Ranch project is completed it is meeting expectations on CO2 supply with the rate of just over 10 million cubic feet per day. Controllable LOE for the fourth quarter in Oklahoma came in at about $12 million or $19.54 per barrel of oil equivalent.

I will close the area of discussions by touching on our Michigan, Indiana and Kentucky properties. Production was 857,000 barrels of oil equivalent for the quarter, which was above forecast despite meaningful downtime due to severe winter weather. We continuously, better than forecasted production in the non-interim in both, the newly drilled DRZ oil wells at Beaver Creek and in the existing Prairie du Chien wells.

Full year production was also above forecast coming in at 3.4 million barrels of oil equivalent. Controllable lease operating expenses for the quarter were about $11.25 per barrel of oil equivalent. Capital expenditures in Michigan totaled about $1.5 million for the quarter and included the completion of two drilled wells and two facility optimization projects. We were successful in making some smaller royalty interest acquisitions in Michigan and finished the year with just over $400,000 in purchases at very attractive multiples.

Now turning to 2014, I want to spend a little bit of time discussing our capital program. As Hal said earlier it will be another very active year for us. We expect our full year 2014 oil and gas capital program to be approximately $325 million to $345 million. This does not include capital for new acquisitions. This is an increase in the 2013 levels of approximately $295 million due to the new development opportunities we have in the properties we acquired during 2013 and also due to opportunities we continue to develop in our legacy properties.

In 2014, we anticipate spending virtually 100% of our capital on oil projects across the company with the majority being focused on Texas, California and Oklahoma. We’re planning about 85% of our total capital spending to be focused on drilling, rate generating and facility projects that are designed to increase or add to production oil reserves.

We expect to spend approximately $166 million in Texas, $84 million in California, $53 million in Oklahoma, $9 million in Florida, $8 million in Wyoming and $8 million in Michigan. We plan to drill 168 wells and drilling cost will be about 70% of our total capital spending. Of the 168 wells we plan to drill 98 are expected to be in Texas, 58 in California, 7 in Wyoming, 4 in Michigan and 1 in Florida.

We just mobilized our 4th company operated rig in the Permian Basin and expect to run those 4 rigs for the rest of the year. The rig will be mobilized with Belridge field by mid-March and we expect to have it working there for about six months. In other areas where drilling is planned we will drill for shorter timeframes due to fewer budgeted wells. So layering our planned 2014 capital program on our existing base production, we’re forecasting 2014 production to be between 13.6 million and 14.4 million barrel of oil equivalent. If we achieve the midpoint of production guidance for 2014 it will be an increase of about 27% compared to the 2013 production of about 1 million barrels of oil equivalent.

As you can see this is a significant increase in production enabled by a robust 2014 capital program and our 2013 acquisitions. As we look back on 2013 it was a strong year for the Company despite the temporary production issues that impacted the fourth quarter. During the year, we built a substantial operating presence and operating capability in both the Permian Basin and the Mid-Continent, both of which will target entry areas for BreitBurn, and we operated our legacy assets very effectively throughout the year. We believe the combination of our resources both people and assets, positions the Company very well for 2014 and future years.

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

Jim Jackson

Thank you, Mark. I will start by reviewing selected results for the quarter, comment on our improved liquidity position and the year, and conclude with commentary on 2014 guidance.

Adjusted EBITDA for the fourth quarter of 2013 was approximately $109.4 million compared to $112.1 million in the third quarter of 2013. The decrease was primarily due to lower oil realized prices as a result of widening differentials, downtime from severe winter weather conditions, new drill performance, and CO2 supply delays. For the year we reported adjusted EBITDA of $370.4 million which represented a 32% increase from 2012 and a record for the Partnership as Hal mentioned.

Turning to earnings, we recorded a net loss of approximately $58.8 million or $0.52 per diluted common unit for the fourth quarter of 2013, as compared to a net loss of $25 million or $0.25 per diluted common unit in the prior quarter. The increase in the net loss was primarily due to impairments in Wyoming and Michigan properties as a result of decreases in long-term commodity prices and reserve adjustments due to the lower than expected performance. For the full year 2013, we recorded a net loss of approximately $43.7 million or $0.43 per diluted common unit compared to a net loss of $40.8 million or $0.56 per diluted common unit in 2012.

As you know we are required under GAAP to mark-to-market our commodity derivative portfolio every reporting period. Mark-to-market adjustments on commodity derivative instruments or non-cash items that do not impact our adjusted EBITDA or distributable cash flow. Excluding the effect of mark-to-market commodity losses on our commodity derivative instruments we would have had adjusted net loss of approximately 37.1 million during the fourth quarter and $6.4 million for the full year.

We reported total oil and gas capital expenditures in the fourth quarter of $96 million up from $87 million in the third quarter primarily due to our capital projects in our Oklahoma assets. For full year 2013 total oil and gas capital expenditures were $295 million, an increase of 93% from 2012. And our 2013 capital program included estimated maintenance capital of approximately $89 million and growth capital of approximately $206 million.

Cash interest expense for the fourth quarter and full year 2013 including the impact of realized losses on interest rate derivatives, but excluding the loss on termination of an interest rate swap, where $24.7 million and $80.8 million respectively. These amounts compared to third quarter of 2013 and full year 2012 totals at $21.7 million and $61.9 million respectively.

Now I would like to discuss distributable cash flow for the fourth quarter and the full year 2013. Distributable cash flow was approximately $55.4 million in the fourth quarter. This amount reflects adjusted EBITDA of $109.4 million, less cash interest expense of $24.7 million, as I described earlier, a less assumed maintenance capital of approximately $29.2 million. On a per unit basis distributable cash flow was approximately $0.46 per unit for the quarter. Our coverage ratio for the quarter based on our current monthly distribution rate of $0.1642 per unit was 0.93 times and reflects a number of the operating and other challenges Mark and Hal discussed.

For the year ended 2013 based on adjusted EBITDA, cash interest expense and maintenance capital of approximately $89.3 million, our distributable cash flow was $200.3 million and coverage ratio based on full year distributions of $1.935 per unit was 0.97 times.

Regarding of hedging strategy, it remains a very important part of our business. During the year we increased our oil hedge portfolio by over 85% versus 2012 and our total hedge portfolio by over 41%. Since November we have added hedges on approximately 3.7 million barrels of oil production for the period covering 2014 through 2017 at an average price of $86.10 per barrel and approximately 6 Bcf of natural gas production for the period covering 2014 through 2017 at an average price of $4.15 per an MMBtu.

Assuming the midpoint of our 2014 production is held flat, our production is hedged at 76% in 2014, 72% in 2015, 57% in 2016, and 30% in 2017. Average annual prices during this period will range between $82.20 and $93.70 per barrel oil and $4.15 and $4.95 per MMBtu for gas.

Our hedge book consists principally of swaps and costless collars which make up approximately 96% of our total hedge volumes. We expect to add additional oil and gas hedges in the years 2014 through ’17 and the months ahead and will continue our practice of hedging acquisitions very aggressively. An updated presentation of the Partnership’s commodity price protection portfolio will be made available in the Events & Presentation section of the Investor Relations tab on our website later today.

Now I would like to review our financing activities for 2013. During 2013, we completed two very successful equity offerings. One in February and one in November where the Partnership issued 15 million common units priced at $19.86 per unit and 19 million common units priced at $18.22 per unit respectively. In November, the partnership also issued $400 million of 7% and 7.8% senior notes due in 2020 at a price just above par. In total financing activities in 2013 raised approximately $1 billion 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 short-term borrowings, we then access the debt and equity markets opportunistically overtime to repay those amounts and position us for future acquisition activity. The long-term debt in an equity are more expensive than bank debt, it’s important for us to have a stable and secured balance sheet to fund our assets long-term and also have significant financial flexibility to fund our growth through acquisition strategy. As of year-end, we had $733 million drawn on our credit facility, down from $1.09 billion at the end of the third quarter and at present we’re approximately $747 million drawn on our credit facility which has a borrowing base of up to $1.5 billion.

We’re currently in a good position to opportunistically access the capital markets, if needed. At the beginning of 2014, we filed a shelf registration statement for our common equity ATM program. More recently, we have worked with our bank group to update our financial covenant package. More specifically, we amended our credit facility to replace what were maximum total leverage and senior secured debt incurrence covenants with first; a minimum interest coverage ratio test which requires us to have adjusted EBITDA of no more than 2.5 times interest expense; and secondly a senior unsecured debt basket not to exceed our borrowing base.

These are important modifications that bring our facility terms in line with our current size and greatly increase our financial flexibility. Absent acquisitions, the combination of the common equity ATM program, the revision of our credit facilities covenant package, our ongoing evaluation of alternative capital markets such as the preferred equity market. These items put us in a position to finance the business and maintain a credit profile consistent with our long-term goals without a pressing need for a traditional common equity issuance. This is a very important step for the Partnership.

Now we’ll review 2014 guidance which was included in the press release we issued earlier this morning. As Hal and Mark mentioned, excluding acquisitions we’re projecting production for 2014 to be between 13.6 million and 14.4 million Boe. We project our current production mix to be approximately 58% oil, 8% NGLs, and 34% gas for the year. In addition approximately 24% of our total oil production is expected to be sold based on Brent pricing. We expect price differentials to be in line with recent levels as detailed in the guidance table included in this morning’s release.

We are expecting other revenues primarily comprised of pipeline revenues and equity earnings and affiliates of between $3.5 million and $4.5 million during the year. These are principally from the Postle related midstream assets we acquired last summer. And our operations team will continue to focus on controlling costs in 2014. We expect 2014 operating cost to be between $18.50 and $20.50 per Boe. These estimated operating costs include lease operating expenses, processing fees and transportation expense. Expected transportation expense totals approximately $6 million in 2014 largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs per Boe are expected to range between approximately $18 and $20. When estimating operating costs for 2014 we are assuming flat $95 per barrel WTI oil, $105 per barrel Brent oil and $4 per Mcf gas price levels.

Production taxes are expected to range between 6.5% and 7% of total oil and gas revenues. We expect 2014 general and administrative expenses excluding unit-based compensation and any future acquisitions to be between $51 million and $53 million or approximately $3.71 per Boe based on the midpoint of our production guidance range.

We are forecasting cash interest expense for the year of between $117 million and $120 million which reflects interest on both our expected bank borrowings and our existing senior notes. The interest expense on the bank credit facility assumes a one-month LIBOR rate of 25 basis points plus the applicable LIBOR margins as per our credit agreement.

The Partnership expects to generate adjusted EBITDA at non-GAAP measure of between 500 million and 510 million in 2014. This range is based on the number of the operating and other assumptions including commodity prices remaining at or near the oil and gas price levels mentioned earlier and reflect the benefit of the Partnership’s existing hedge portfolio.

Total capital expenditures excluding any 2014 acquisitions are planned to be between $325 million and $345 million and this includes estimated maintenance capital of $125 million, plus growth capital expenditures of between $200 million and $220 million. Based on these estimates we expect distributable cash flow to range between $255 million and $260 million during the year.

In conclusion I would like to reiterate that 2013 was a very productive year for the Partnership. We were successful in significantly growing your asset base and exposure to oil, expanding our presence in the Mid-Continent and executing on one of the most active capital programs in our history. In addition, we far exceeded our target acquisition goal and achieved a record production and adjusted EBITDA. 2014 will be another important year for the Partnership and we remain committed to delivering long-term values to our unitholders.

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

Question-and-Answer Session

Operator

(Operator Instructions) We will take our first question from Noel Parks from Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Good morning.

Hal Washburn

Good morning, Noel.

Noel Parks - Ladenburg Thalmann

I just had a couple of things, first about the Permian. Is there a potential in your thinking to go down below on 20 acre spacing, like say to 10 acres?

Hal Washburn

Definitely, we haven’t done any of that yet on a widespread basis, but when you look at the way that some of our current well’s spaced because of the different leases, they’re effectively. Some are more effectively on 20 acre spacing. And we haven’t seen any impacts of drainage, so we definitely believe there is potential to down space.

Noel Parks - Ladenburg Thalmann

Okay, great. And you also said that your experience now shows that it’s taking longer to reach the peak production rate in the new drilled wells out there, and what do you attribute that to?

Hal Washburn

Well, I would say part of that was, we haven’t operated out there before we did the Permian Basin acquisitions, and as we looked that them in our initial look we thought the wells would clean up, when you do the stimulations on, you put fluid on the formation. We thought the wells would clean up in the first month, and they're just taking longer to clean up than that. So, while our peak rates are still okay, it just takes it a little bit longer to get there, so you can see when you drill a bunch of wells in one quarter the wells that you drilled in a delayed quarter, you don’t get near the production response on them, as if they’d ramped up in the first 30 days.

Noel Parks - Ladenburg Thalmann

I got you, okay. And I noticed that you did add in another good bit of hedging ’14 is pretty well hedged, but even in ’15 and ’16, and we’ve had some pretty decent strengthening in the strip, probably the best we’ve had at least a few quarters. And looking ahead I was wondering if you’re inclined to get more aggressive on hedging or on the other hand pause, I guess, I was sort of wondering we have seen the top of the strip for ’15 and ’16, by your thinking?

Hal Washburn

Noel, this is Hal. We gave up about 24.5 years ago on trying to predict the top of the market or the bottom of the market for oil and gas prices, so we’re very consistent the way we hedge. So what you see is a significant amount of hedging in conjunction with the acquisition. So you saw acquisitions in the end, at very end of the fourth quarter, the CQ 3 the CrownQuest three acquisitions that we did as well as the Postle acquisition and a lot of hedge volume coming into the book is associated with those acquisitions. We will continue to be consistent. We are adding hedges where we think it makes sense, strengthening the book but we’re not trying to time the market or pick the high point or the low point, sometimes we get lucky to do that but usually we’re just trying to be consistent.

Noel Parks - Ladenburg Thalmann

Sure, I guess I was thinking especially to the degree you have got a good bit of a production hedged to Brent, it sort of just seems that if anything prices have been surprising a little bit to the upside with oil lately, I just wondered if maybe you were inclined to maybe be a little bit less aggressive and just see if you could capture a bit of that upside in the event that we’re -- and I mean just maybe delaying by a quarter or two what you might normally do just to see how things pan out?

Hal Washburn

Yes, we’re monitoring market and we’re looking at it every day and our risk management group is in that marketplace. The market is very backward dated and it’s been a rolling wave for a while now, and that does have us less inclined to go in the market further out, so I think you know, we’re trying to get the benefit of the shape of the curve, but our policy is really pretty consistent. We want to keep those hedges at the stated goals, kind of 80% year one, and 75% or so year two there and so on.

Noel Parks - Ladenburg Thalmann

Great, that’s all from me, thanks.

Hal Washburn

Thank you.

Operator

We’ll take our next question from John Ragozzino from RBC Capital Markets.

Hal Washburn

Hey, John.

John Ragozzino - RBC Capital Markets

Hi. Good morning guys, I just have one quick one for you Jim. It’s been quite a long morning of three back-to-back calls. Think back to last year at this time, since you had a rough target of about $500 million in unofficial A&D target and clearly knocked that number off the charts with the Postle acquisition. Do you have a number in mind that you think about for 2014 when it comes to an acquisition program that would leave you satisfied?

Hal Washburn

Well John, we’re never satisfied, this is Hal not Jim, but I jumped in just because Jim will give you a lower number than me, so, what we said earlier on the call is our target is at least $600 million in acquisitions this year. And we think that…

John Ragozzino - RBC Capital Markets

I apologize for not getting there.

Hal Washburn

No problem we think that that will -- that combined with the operating and capital plan we have allow us to continue to increase our distributions, so that’s our target for the year right now, at least 600 million.

John Ragozzino - RBC Capital Markets

Thank you very much, I appreciate it.

Hal Washburn

Thank you.

Operator

We’ll take our next question from Praneeth Satish from Wells Fargo.

Praneeth Satish - Wells Fargo Securities

Hey guys.

Hal Washburn

Hi, Praneeth.

Praneeth Satish - Wells Fargo Securities

Good morning or afternoon, just a couple of quick questions from me. The 2014 guidance, the interest expense figure there, does that assume any aftermarket equity issuance this year?

Hal Washburn

No it doesn’t.

Praneeth Satish - Wells Fargo Securities

Okay. And then the cash G&A is forecasted to be up quite a bit in ’14 relative to the run rate in the fourth quarter, can you just talk about the factors behind that?

Hal Washburn

Sure, a lot of that is the full year effect of adding staff throughout the year here, which we’ve been doing actively just to keep pace with the business, I mean I think that from our perspective Praneeth the key metric is cash G&A per Boe and our G&A target for the year of I think just over $3.70 is, compares favorably to where we’ve been in the past and we think compares favorably versus the peer group.

Praneeth Satish - Wells Fargo Securities

Okay. And just last question from me, I mean historically you’ve had a fairly consistent track-record of raising the distribution every quarter, has anything changed there, based on what you see with your 2014 guidance are you may be looking to time the distribution increases more opportunistically with acquisitions or are you still comfortable with the current strategy?

Hal Washburn

We’re still comfortable with the current strategy as we have said and I think we said again in the call, we have to do two things well to continue to increase distributions, we have to operate our existing production, we have to deploy our capital on organic projects and we have to make acquisitions. And we think we can do both one and two very well and we believe that the acquisition market for 2014 will be robust and we’ll be able to do the third too. So, if we hit our $600 million in acquisitions this year we believe we’ll be able to continue the distribution growth that we’ve been, trajectory that we’ve been on.

Praneeth Satish - Wells Fargo Securities

Okay, great. Thank you.

Hal Washburn

Thank you.

Operator

(Operator Instructions) We’ll take our next question from Michael Peterson from MLV & Company.

Hal Washburn

Hey, Michael.

Michael Peterson - MLV & Company

Good day, everyone. My first question is a little bit more broad and strategic in nature. I’ve heard some folks characterize operating in California as being comparable to operating on foreign soil and real or perceived this may have kept some of your otherwise domestic peers out of the golden state. My question regards Occidental’s interest in repositioning its California asset base. Does this open up any significant opportunities for BreitBurn that might not necessarily avail themselves to other of your peers that don’t operate in California?

Hal Washburn

We certainly think we have a competitive advantage being here, there is that perception, we’ve been here for more than 25 years, frankly the highest margin barrels we have are those barrels we produce in California so from our perspective it’s a good place to operate but it does take some coming from the Mid-Continent or from some other basins it does take a little bit to come in here.

We’re not sure what’s going to happen with Occi, we hear the same thing. We read the same releases that you do. One thing about the California market is. Is that it’s pretty unique. There’s just a consolidation that you have here, when you look at the production in the state you take Exxon and Shell through their Arrow joint venture, you take Chevron, you take Occi and may be add in PXP Freeport and you’ve got probably three quarters of the state’s production accounted for.

So there’s not a lot of production that trades in California and so many reasons that we have continued to grow outside of the state. But if you see one of those big operators, like Occi who operates the most production in the state, start to think about what their future looks like it could provide a lot of opportunities for us and we think we’re well positioned to take advantage of those opportunities.

Michael Peterson - MLV & Company

Okay, that’s helpful, thank you Hal. Mark in your operational comments you mentioned sourcing some CO2 from Bravo Dome. Are there additional CO2 volumes available either from Bravo Dome or elsewhere as you need them in 2014?

Mark Pease

Thanks for calling in Michael, with what we have got now I touched on, we already had a contract with Exxon that we were receiving CO2, and we were able to go back, amend that contract, get some additional volumes and those are the volumes I touched on during the script. But we believe the combination of the increased volumes from Exxon and the Libby Ranch coming on will take care of current deals we have, North East Hardesty and Postle, but as we look, and I think we’ve talked about this in the past, we believe that that whole set of assets we have up there, the fields, the pipelines, the CO2 facility is a great anchor asset to grow on the area. So if we’re able to do some of the things that we like to do, then we’ll certainly look to see if we can’t source more CO2 out of Bravo Dome. There is additional CO2 there and I’m sure you’re well aware Michael the CO2 is inside the same very tight supply just about every quarter.

Michael Peterson - MLV & Company

Understood, understood, so if I can re-characterize what you just said, you don’t see build out of the acreage being constrained by an inability to get the CO2, while it’s not easy to get, it is available if you were to need it to pair with an additional asset?

Mark Pease

And maybe a better way to say it is, we currently have our under contract CO2, we need to take care of the fields that we currently own, and we believe that we can get our arms around some other fields, new fields we believe we can find CO2 to take care of us.

Michael Peterson - MLV & Company

Great, thanks for the clarification Mark. Gentlemen, that’s all I have today.

Mark Pease

Thank you, Mike.

Hal Washburn

Thanks Michael.

Operator

And it appears there are no further questions at this time. (Operator Instructions) And our next question comes from Doug Christopher from Crowell Weedon.

Doug Christopher - Crowell Weedon & Company

Hi, thank you very much, thank you for the details and the release and the call today, I appreciate that. Separate issue, there’s been questioning about Kinder Morgan’s CO2 operations and how they account for maintenance versus growth CapEx. Can you make a comment on that, comment on the Dow Jones news yesterday, saying you look at their exploration and production operations discussing the CO2, if their existing volumes cannot be maintained without a certain spending level all of that should be considered maintenance CapEx. Can you maybe discuss how that relates to you and these newer operations that you have with the CO2?

Hal Washburn

Sure, and this is Hal. I don’t want to comment on Kinder Morgan, we haven’t yet studied that but I can tell you we’ve studied our maintenance capital spend, our maintenance capital requirements pretty closely, very closely and we have a very rigorous approach and as we have said in the past and I went through it again. Each year is part of our formal capital budgeting process. We have a very thorough view of maintenance capital. We look at the year-end reserve report performed by our third-party engineers. We look at our multiyear capital plan and our Board approved capital budget and we estimate the amount of investment capital projects that add production plus we add obligatory spending on existing facilities and operations and come up with a total that’s needed to hold production approximately constant year-over-year. And so we do that process each year, and that process in 2004, 2014 yielded $125 million maintenance capital estimate. So we’re basically doing a thorough analysis of what it takes to hold our production flat year-over-year.

Doug Christopher - Crowell Weedon & Company

Thank you very much.

Hal Washburn

Thank you.

Mark Pease

Thanks Doug.

Operator

It appears there are no further questions at this time. Hal Washburn, I’d like to turn the conference 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. And operator you can now bring this call to a close.

Operator

This concludes today’s conference. Thank you for your participation.

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