Greg Brown - General Counsel of BreitBurn
Hal Washburn - CEO
Randy Breitenbach - President
Mark Pease - COO
Jim Jackson - CFO
Joel Havard - Hilliard Lyons
Breitburn Energy Partners LP (BBEP) Q3 2010 Earnings Call November 4, 2010 12:00 PM ET
Welcome to the BreitBurn Energy Partners Investors 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, Security Analysts and Institutional Portfolio Managers will be invited to participate in the question-and-answer session. (Operator Instructions)
As a reminder, this call is being recorded Thursday, November 04, 2010. A replay of the call will be accessible until midnight Thursday, November 18th by dialing 877-870-5176, and entering conference ID 7476456. 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 and General Counsel of BreitBurn. Please go ahead, sir.
Presenting this morning are Hal Washburn, BreitBurn’s CEO; Randy Breitenbach, BreitBurn’s President; Mark Pease, BreitBurn’s Chief Operating Officer; and Jim Jackson, BreitBurn’s Chief Financial Officer. After their formal remarks, the call will be opened up for questions for Security Analysts and Institutional Investors.
Let me remind you that today’s conference call contains projections, guidance and other 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 current expectations and assumptions about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change from those we projected over the course of the year.
A detailed discussion of many of these uncertainties is set forth in the cautionary statement relative to forward-looking information section of today’s release and under the heading risk factors incorporated by reference from our annual report on Form 10-K for the year ended December 31, 2009, our quarterly reports on Form 10-Q, our current reports on Form 8-K and our other filings with the Securities and Exchange Commission.
Unpredictable or unknown factors not discussed in those documents also could have material adverse effects on forward-looking statements. The partnership undertakes no obligation to update publicly any forward-looking statements to reflect new information or events.
Additionally, during the course of today’s discussion, management will refer to adjusted EBITDA, which is a non-GAAP financial measure, when discussing the partnership’s financial results. Adjusted EBITDA is reconciled to its most directly comparable GAAP measure in the earnings press release made earlier this morning and posted on the Partnership’s website.
This non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.
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. This non-GAAP financial measure 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 in the same manner.
With that, let me turn the call over to Hal.
Welcome everyone and thank you for joining us today to discuss our third quarter 2010 results. As we stated earlier this year, the Partnership has made return to normal operations its primary focus for 2010 and as evidenced by our solid third quarter results, we continue to deliver on our goals.
During the third quarter we produced 1.74 million barrels of oil equivalents for 18,927 barrels of oil a today, which trends above the high end of our guidance range. Lease operating expenses, excluding transportation fees and property taxes once again and in below our guidance range at $16.54 per Boe.
Capital spending increased in the third quarter to $25.6 million inline with full year 2010 capital spending guidance. Mark will elaborate in a few minutes, but our operating team has done an excellent job of efficiently executing capital program we put into place for the year.
Additionally, we continue to focus on control the operating expenses and year-to-date our financial and operating results continue to exceed guidance expectation. Although the markets have stabilized considerably since the spring of 2009, we continue to believe in importance of preserving our financial flexibility.
In October, we closed our first senior notes offering, which was very well received and over subscribed. We eventually upsized the transaction from $250 million to $305 million and priced for the coupon rate of 8.625%. The notes are due in 2020 and $290 million of the net proceeds were immediately used to reduce our borrowings on our credit facility.
Jim will go into additional details on our current liquidity position shortly, but overall we greatly reduced our reliance on short-term variable rate bank credit facility in favor of long-term fixed rate senior notes.
Last week, we announced that our Board of Directors approved an increased distribution for the third quarter. The new distribution of $0.39 per unit or $1.56 per unit on an annualized basis represents a 4% increase in distribution since we reinstated distributions for the first quarter of this year in April. It will be paid on November 12, 2010 the record holders of common units of the close of business on November 9th.
Based on a $1.56 distribution run rate and our conservative public guidance for 2010 distributable cash flow, approximately $120 million, which assumes maintenance capital expenditures of $40 million to $50 million.
Our distribution coverage ratio is approximately 1.4 times. As we stated before, our long-term coverage ratio target is around 1.2 times, and we will continue to consider quarterly distribution increases based on our operating performance, the commodity price environment and other key factors as discussed in our public filings.
With that, I will turn the call over to Randy, who will cover additional highlights, discuss selective results for the quarter and the year, and recap our hedged portfolio. Randy?
I will address some details of our commodity hedging activity and the impact of the derivative instruments on our third quarter 2010 results. In the third quarter, crude oil and natural gas sales including realized gains and commodity derivative instruments totaled $99.6 million, down slightly from $100.5 million in the second quarter of this year.
Our commodity hedge portfolio continues to play a positive role supporting our oil and gas revenues. Realized gains on commodity derivative instruments for the third quarter and second quarter of 2010 contributed $22.6 million and $18.4 million respectively, the total sales.
Our realized oil and gas prices continue to compare favorably to WTI crude oil and very favorably to NYMEX natural gas prices for the same period. For the third quarter, our realized crude oil and liquid prices averaged $76.14 per barrel on par with WTI spot prices for the period of $76.06 per barrel and our realized natural gas prices averaged $7.55 per Mcf well above NYMEX natural gas prices for the quarter of $4.24 cents per Mcf.
In September, we entered into new natural gas hedges covering approximately $1.8 million MMBtu of 2013 production at a price of $5.51 per MMBtu and new oil hedges covering approximately 365,000 barrels of 2014 production at a price of $87.20 per barrel.
In October, we added additional oil hedges covering approximately 1.4 million barrels of 2011 through 2014 production at a price of $87.75 per barrel, and in November we added new natural gas hedges covering approximately 1.8 million MMBtu of 2013 production at a price of $5.25 per MMBtu.
An updated summary price protection portfolio would be posted on our website today. As you know, we have a stated strategy of maintaining maximum visibility on our cash flows, so you are likely to see starting delay in more natural gas hedges in those out years consistent with our goal.
Our substantial hedge portfolio is one of the key strengths of the Partnership and a proven successful in mitigating commodity price volatility, stabilizing revenues in cash flows, and supporting our borrowing base in the past.
Our current hedge portfolio, assuming the midpoint of 2010 production guidance is held flat. It’s hedged at 86% in 2011, 75% in 2012, 71% in 2013, and 21% in 2014. Averaged annual prices during this period range between $79.90 and $88.88 per barrel for oil and $6.50 and $8.26 per MMBtu for gas.
As a significant portion of our oil and gas volumes are well protected at attractive prices during the next four years. We remain in a very strong position going forward.
With that, I will turn the call over to Mark, who will provide you with additional details of our operating performance. Mark?
We had a very successful quarter from an operational perspective. I will run through the results at the Partnership level and then discuss some of the details by division.
During the third quarter, we produced 1.74 million barrels of oil equivalent, which equates to 18,927 barrels of oil equivalent per day, a 4% increase versus the prior quarter production 18,270 barrels of oil equivalent per day.
As Hal mentioned earlier, our production is currently trending just above the high-end of our 2010 guidance range. The production split for the quarter was approximately 53% natural gas and 46% crude oil and NGL.
Leased operating expenses and processing fees, excluding transportation expenses and property taxes came in at $28.8 million or $16.54 per Boe for the third quarter, which is 7% lower on a per Boe basis than the $17.82 per Boe we incurred during the second quarter of this year.
The lower LOE per barrel number is primarily due to our continued strong focus on controlling costs and certainly helped by the higher produced volumes during the quarter. Across the company, costs of materials and services have remained relatively flat since the last quarter.
Total capital expenditures in the third quarter were $25.6 million. This is consistent with our 2010 capital spending program in which the bulk of our program is executed in the second and third quarters. If you recall, we only spent $8 million in the first quarter followed by $20.9 million in the second quarter. Year-to-date we have spent about $54.5 million and we expect full year capital expenditures to come in at the high end of our guidance range.
Both our Eastern and Western divisions continue to deliver excellent results. I will start with some of the details on results from our Western division. Production in the Western division, which includes California, Wyoming and Florida, was about 4% lower than expected due primarily to the delayed completion of the second horizontal well at the Raccoon Point field in Florida.
Our first horizontal well the [275-A Age] continues to perform very well averaging about 630 barrels of oil equivalent a day grows for the month of September. We expect initial results on our second Florida well sometime in the fourth quarter. We completed the 2010 drilling program for Wyoming. Drilling and completing seven wells during the third quarter all of which essentially came in at focus. Overall our 2010 Wyoming drilling program came in about 5% better than forecast on both production and cost.
Controllable lease operating expense per barrel was lower than forecast in Western due in part the lower utility cost in California and continued focus on (inaudible) sending.
Now, let us move to Eastern division, which includes Indiana, Kentucky and Michigan. Production was almost higher than forecast due primarily to better than anticipated result for the overall Eastern division capital program and continued strong performance from three (inaudible) Shane wells that we have drilled or recompleted during the last several months. Current combined gross production from these wells is 6 million cubic feet per day and 600 barrels of liquids per day.
Controllable lease operating expense per barrel on the eastern division was significantly lower than forecast mainly to lower compression related expenses and lower non-operated LOE. Low natural gas prices have had a meaningful impact on costs as a majority of servicing materials demand in that area is driven by natural gas based activity.
On the capital side, we completed 8 drill wells, 16 well work-overs and two facility optimization projects which added incremental net production of 1.4 million cubic equivalent per day.
Let me provide a quick update on calling Collingwood Utica activity. We have been actively requiring new leases and amending existing leases to add to existing Collingwood Utica position. As of October 22, 2010, we hold approximately 125,000 net acres in the prospective Collingwood Utica trend. At the latest Michigan State lease sale last week we required about 4,400 additional net acres in the trend or approximately $225,000, an average of about $51 per acres.
In that lease auction, state sold a total in approximately 274,000 acres for $9.65 million and an average of about $35 an acre. Although the average cost per acre for this lease auction was well below that of the auction held in May there is still interest and potential in the Collingwood Utica play. Of the deep acreage that we hold in the play, approximately 90% of it is held by production. This gives us much flexibility as we continue to evaluate our options going forward.
Overall, we had another strong quarter of operating results with both production and cost coming in better than forecast with the quarter.
With that I will turn the call over to Jim.
Thank you, Mark. I will give some additional detail on our financial results and comment on our improved liquidity position.
Oil and natural gas revenue including realized gains and losses on commodity derivative instruments fell very slightly in third quarter to $99.6 million compared to $105 million in the second quarter of the year. Realized gains on commodity derivative instruments were $22.65 million, up from $18.4 million in the prior quarter.
Oil and natural gas liquid sales were impacted by the lower sales volumes related to the timing of oil sales in Florida partially upset by high average crude oil prices. Third quarter adjusted EBITDA was $60 million, up approximately 6% from the $56.7 million in the second quarter and trending above the high end of 2010 annual EBIDTA guidance range of $190 million to $200 million primarily due to lower operating costs.
General and administrative expenses excluding non-cash unit based compensation expense for the third quarter were $7.2 million or $4.13 per BOE versus $5 million or $3.01 per BOE in the second quarter of 2010.
For 2010, we expect G&A per BOE to trend towards the full year guidance of process of $4 for BOE.
Production and property taxes totaled $5.1 million in the third quarter as compared to $4.2 million in the second quarter. Net interest and other financing cost excluding realized and unrealized gains and losses on interest rate swaps for the third quarter were $5.1 million compared to $5 million in the second quarter of 2010.
Cash interest expense, which includes realized gains and losses on interest rate swaps, but excludes debt amortization expense and unrealized gains and losses on interest rate swaps, totaled $7 million in the third quarter of 2010 versus $6.9 million in the second quarter.
We expect cash interest expense to increase slightly in the fourth quarter due to our recent senior note issuance that expect full year interest expense on a cash basis to be within our 2010 guidance range.
On a side note, in September we added new interest rate swaps covering approximately $100 million for periods from 2011 to 2011 on a fixed interest rate of approximately 1.16%. We recorded a net loss of $5.7 million, $0.11 for limited Partnership units for the third quarter versus net income of $53.6 million or $0.94 per unit for the second quarter 2010.
These results include the effects of unrealized losses on commodity derivative of $30.5 million in the third quarter of this year and unrealized gains of $33.2 million in the second quarter.
Now let me return to our liquidity position. Our outstanding borrowings at the end of the third quarter were $516 million, as compared to $534 million at the end of the second quarter.
As Hal mentioned, we completed our first senior notes offering in early October. The notes for prices with coupon of 8.625% and will mature in 2020. Our borrowing days is reaffirmed at $735 million on October 5th and for the terms of our credit facility was reduced to $659 million following the completion of the senior notes associated.
As of October 31st outstanding borrowings under our credit facility totaled $220 million, total debt was $520 million and available liquidity under our credit facility was $439 million.
Through 2010, we have been focused on our core strategies have announced excellent operating and financial results that has exceeded expectation. We have announced consistent increases in distribution since (inaudible) in April and we hope to deliver another solid quarter results to cap the year.
This includes our formal remarks. Operator you may now open the call for questions.
(Operator Instructions) From Hilliard Lyons we will go to Joel Havard.
Joel Havard - Hilliard Lyons
On the development comments at the beginning I wanted to make sure understood where those net additions the seven in Wyoming and eight in the Eastern?
Yes. They are.
Joel Havard - Hilliard Lyons
If you got a sense yes, I believe you all said something previously about seeing approximately 40 net for the year is that still look achievable?
Yes. We are right on that number.
Joel Havard - Hilliard Lyons
Finally, can you give us a sense of where we are on a percentage basis maybe through the optimization process or is that in fact something that really never ends?
You are talking about operating costs and operations?
Joel Havard - Hilliard Lyons
Yes. Apparently, there is a number of approaches that you guys are taking, but where you are going through these optimization efforts and Michigan has been a big focus of that. Given me a better sense of how far through that process you are versus maybe it never stops?
Your last comment is accurate. It never stops. The process we run through there is specifically speaking about Michigan, when we got control of that assets, we go through and we do high grade our projects every year in our capital program. We do our highest credit return projects first.
Maybe you can call that [low hang] improved and I’d say that we believe or three months to below hanging improve, but we still got projects through economics and you’ll see those continue to be down. Most of what we’re doing when we talk about optimization or facility optimization project and the results from those things, those are just math, it's reducing pressure so, we know what kind of response we’re going to get on those, they are very predicable. We continue to evaluate those every year.
Joel Havard - Hilliard Lyons
What would be a hypothetical return hurdle on that? If you hit the long end and I am concerned that would we see higher operating expenses as a result or a lessened positive impact on the production side?
No, you wouldn’t actually say higher operating expenses, part of operating expenses realizing right now are due to those optimizations we have already done. As we did more, you’ll continue to see them come down and we don’t really talk about our rate of return hurdles on each one of these projects. As you well know very highly correlated to commodity price, very highly correlated. We test all these things down to we stress-test them down to local dollars and Mcf and now a positive rate of return and if you go to still the higher prices in that then the rates of return are very, very, very good.
(Operator Instructions). That is all the time we have for questions today, Mr. Washburn, I turn the conference back to you for any closing or additional comments.
On behalf of Randy, 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.
Ladies and gentlemen, this does conclude today’s conference call. Thank you everyone for joining us. You may now disconnect.
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