BreitBurn Energy Partners L.P (NASDAQ:BBEP)
Q2 2009 Earnings Call
August 10, 2009; 1:00 pm ET
Jim Jackson - Chief Financial Officer
Hal Washburn - Chairman & Co-Chief Executive Officer
Randy Breitenbach - Co-Chief Executive Officer
Mark Pease - Chief Operating Officer
Greg Brown - Executive Vice President of Land, Legal and Government Affairs, General Counsel
Larry Smith - Controller
Michael Blum - Wells Fargo
Richard Roy - Citigroup
Yves Siegel - Credit Suisse
Welcome to the BreitBurn Energy Partners investor conference call discussing second quarter 2009 results. The company’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 a question-and-answer session. (Operator Instructions) As a reminder, this call is being recorded Monday August 10, 2009.
A replay of the call will be accessible until midnight, August 17 by dialing 888-203-1112, and entering conference ID 7149020. International callers should dial 719-457-0820. An archive of this call will also be available on this BreitBurn website at www.breitburn.com.
I would now like to turn this call over to Jim Jackson, Chief Financial Officer of BreitBurn. Please go ahead, sir.
Good morning everyone. On with me today are Hal Washburn, BreitBurn’s Chairman and Co-Chief Financial Officer, Randy Breitenbach, BreitBurn’s Co-Chief Executive Officer and Mark Peace, BreitBurn’s Chief Operating Officer. Also with us are Greg Brown, our Executive Vice President of Land, Legal and Government Affairs and our General Counsel, as well as Larry Smith, our Controller.
After our formal remarks, we’ll open the call for questions from securities analyst and institutional investors. Before I turn the call over to Hal, 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 our current expectations and assumptions, many of which are beyond our control about future developments. 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 statements 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, 2008, 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 tests. 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.
Thank you, Jim. Welcome, everyone. The second quarter of 2009 was a very good quarter for the partnership. Operationally, we’re on track for a successful year with quarterly results at the high end of annual guidance. In April, following a borrowing base re-determination, we announced the temporary suspension of distribution in an effort to focus on paying down borrowings under our credit facility.
We have made meaningful progress in this regard and debt reduction has been accelerated with the monetization of $25 million of hedge contracts in June and the sale of our non-core Permian Basin assets for $23 million in July.
To emphasize our debt reduction efforts, let me bring your attention to our outstanding bank borrowings as of June 30, 2009. The partnerships borrowing, as of quarter end was $640 million, which represents a reduction of $67 million since March 31, 2009 and a reduction of 123 million since year end 2008.
As of July 31, our outstanding borrowings were reduced to $613 million. While we’re not announcing the reinstatement of distributions this quarter, we’re certainly on our way to the stated goal. As we’ve said in the past, the timing of such an announcement is based on a number of factors, including, and perhaps most importantly our next borrowing base re-determination in October.
We remain committed to evaluating all reasonable alternatives to further reduce debt and reinstate distributions, and we’ll pursue them if management and the board determine they are in the best long term interest of our unitholders.
Now, let me turn to a few second quarter highlights, total production for the quarter was on target with the high end of our guidance range and totaled 1.654 million barrels of oil equivalent, which represented 3% increase from the first quarter of 2009. We’re very pleased with this result, especially with the performance of our Eastern division, which exceeded production expectations. This accomplishment is notable, given our dramatically lower capital spending levels for the quarter and the year.
We continue to review opportunities for operating in general and administrative cost reductions and have eliminated a number of staffing positions, while progressively negotiating with third party service providers to lower vendor costs. Mark and Jim will provide more details in their discussions.
Adjusted EBITDA, which excludes the impact of the June monetization of hedge contracts, increased 9% on a quarter-over-quarter basis to $50.8 million from $46.8 million. On an annualized basis, our second quarter adjusted EBITDA is above our 2009 guidance range.
As I mentioned earlier, at the beginning of the year, we announced that we would significantly reduce our capital spending for 2009. However, given the recent improvement in oil prices, we’ve decided to increase our capital spending plans for 2009 from the announced guidance range of $20 million to $24 million to approximately $32 million.
We are in the enviable position of having a balanced portfolio of oil and gas opportunities and these increased expenditures will be focused primarily on our oil properties and will help us move much closer to our goal of returning the pace of our capital spending to the level necessary to hold production flat going forward.
On June 29, we announced the termination of selected 2011 and 2012 hedge contract. Net proceeds from this transaction totaled approximately $25 million, which was immediately used to pay down borrowings under our credit facility. Our borrowing base, which has been lowered to $760 million during April’s borrowing base re-determination process from $900 million, was subsequently reduced by $25 million to $735 million.
Concurrent with the termination of the 2011 and 2012 contracts, identical volumes were re-hedged at prevailing market prices. In light of improvements in commodity prices over early 2009 levels, we took the opportunity to reinforce our near term hedge portfolio by adding new hedges in 2009 and extend price protection out 4.5 years by adding new hedges in 2013. Randy, will provide additional color in his discussion.
Subsequent to the end of the second quarter, we sold our Permian Basin assets, also known as the Lazy JL Field on July 17, to a private buyer. These non-core assets produced approximately 245 barrels of oil equivalent per day during the first five months of 2009, with crude oil amounting to approximately 96% of production. The attractive sales price of $23 million represented $94,000 per flowing barrel of oil equivalent.
All proceeds were used to accelerate debt reduction efforts with limited impact on the borrowing base, as the sale only reduced our borrowing base by $3 million. We continue to actively evaluate opportunities for other asset sales and dispositions of our other non-core properties, as part of our review of all of our debt reduction alternatives.
With that, I will turn the call over to Randy, who will briefly cover some of the operating highlights and discuss hedging activity during the quarter. Randy.
Thank you, Hal and welcome everyone. As we have mentioned in previous quarterly calls, the partnership uses commodity and interest rate derivative instruments to mitigate the risks associated with commodity price volatility, and changing interest rates and help maintain predictable cash flows. As it did in the first quarter of 2009, our extensive hedge portfolio provided significant price support and alleviated the impact of considerable year-over-year declines in oil and gas prices.
In fact, we recognized an increase in crude oil and natural gas sales revenues, including realized gains and losses on commodity derivative instruments on a year-over-year basis. Furthermore, we have extended our hedging portfolio into 2013 at attractive pricing levels of $7.50 for gas and $76.62 for oil.
Now let me provide you with some details of our commodity hedging activity and the impact these derivative instruments on our second quarter results. In June, we announced a $25 million hedge monetization of select in the money in 2011 and 2012 hedge contracts. The net proceeds from the monetization, as Hal mentioned, were immediately used to reduce partnership’s credit facility.
Non-cash unrealized losses from commodity derivative instruments were approximately $148.7 million due primarily to the increase in oil prices over the period. The effect of the $25 million in hedge contract monetized in June 2009 is reflected and realized in unrealized gains and losses on commodity derivative instruments. Excluding the effect of the monetization, realized gains on commodity derivatives would have been $26.5 million, and unrealized losses would have been $123.7 million.
Please note that the impact of the monetization is also excluded from the calculation of realized prices and adjusted EBITDA for the second quarter of 2009. Simultaneous with the hedge monetization in June of select 2011 and 2000 contracts, we rehedged identical volumes in those same years at market prices. Additionally, given the increase in oil prices and the Contango and gas futures pricing, we’re bolstered our hedge portfolio by adding new oil hedge contracts in 2009, and oil and gas contracts in 2013.
Assuming currently production levels are held flat our oil and gas volumes are very well protected with hedges in place through 2013. More specifically, 85% of our second half of 2009, oil and gas production is hedged at average prices of $72.79 per barrel, and $8.19 per MMBtu. 80% of our 2010 oil and gas production is hedged at average prices of $81.48 per barrel and $8.26 per MMBtu.
70% of our 2011 oil and gas production is hedged at an average price of $77.60 per barrel and $7.92 per MMBtu. 64% of our 2012 oil and gas production is hedged at average prices of $88.35 per barrel and $8.05 per MMBtu, and 36% of our 2013 oil production and 5% of our 2013 gas production is hedged at average prices of $76.62 per barrel, and $7.50 per MMBtu respectively.
These amounts include that hedging benefits of our Florida sales contracts. Given the current prices for oil and gas, our extensive hedge portfolio provides significant price support for the next four years. A complete summary of our hedge portfolio as of June 30, 2009, is available in our 10-Q filed today as well as today’s earnings release.
Our second quarter results highlight the success of our hedge strategy as a price protection tool which moderates commodity price volatility and protects revenues. We have made every effort to build strong hedging positions that lock in steady cash flow. Furthermore with the relative improvements in commodity prices, we are looking at additional out of year hedges on an ongoing basis.
Now let me turn the call over to Mark Pease who will provide you with additional details of our operating performance. Mark?
Thanks, Randy. We had a very strong second quarter. I’ll run through the operating results at the company level and then give some detail on the key activities and issues in the different operating areas. Let’s start with production. During the second, the company produced 1.65 million barrels of oil equivalent, which on an annualized basis is on the top end of our guidance range.
Q2 production was up 3% compared to Q1 production, with production being flat or up in all areas except Texas. As we discussed in our last earnings call, we replaced Senior Management in the Eastern division, which includes Michigan, Indiana and Kentucky. We are seeing the benefits of these changes and moving out of the winter season, as the Eastern division had the largest quarter-over-quarter production increase. The production mix for the company was as outlined in our guidance 54% gas, and 46% oil.
Lease operating expenses, transportation fees and processing fees, which are our controllable operating costs, came in at $17.40 per barrel oil equivalent. This is 7% below Q1 cost of $18.69 per Boe and is significantly below the midpoint of our yearly guidance of $16.75 to $19.25 per Boe.
Let me give some additional color on cost trends. We have previously discussed the strong connection of material and service cost to the price of oil and natural gas. As commodity prices increase, demand for materials and services increases, and those costs rise with a lag relative to commodity prices. The same is true when commodity prices fall. Service and material costs fall with a lag relative to commodity prices.
We continue to put a very, very strong focus on costs and expenses across the company, and we continue to see results from those efforts. Some examples are, casing and tubing costs went down 10% to 15% during the second quarter. Costs for sucker rods were down as much as 10% during the quarter, and costs for chemicals and work-over rigs were down 5% to 10% in certain areas during the quarter.
Commodity prices assumed in our guidance at the beginning of the year were $40 per barrel of oil and $4 per Mcf flat for 2009. For the first half of the year, actually prices have averaged $51.68 per barrel, and $4.12 per Mcf, higher than those used in our guidance.
We are seeing a slowing trend in the rate at which materials and service cost are falling. This will be an area of continued strong focus for us. Our operating teams have been doing an excellent job in these efforts. Capital costs for Q2 came in at $3.9 million. This puts the first half of 2009 capital spending at $11.1 million, which is right in the middle of our guidance of $20 million to $24 million for the year.
A couple more comments about our capital program this year. During the first half, we spent significantly less than our maintenance capital level, which we define as the spending level required to keep production flat. Daily production for the year rose Q2 versus Q1, and the Q2 daily production rate is only 1% less than our daily rate in Q3 and Q4 of 2008. This is a result of the high-grading that has been done on our 2009 capital projects, and also the connection of shutting gas wells in Michigan in late 2008 and early 2009.
Projects done so far in 2009 have been about 50/50 oil and gas. With our reserves and portfolio of opportunities split about evenly between oil and gas, it gives us the flexibility to shift capital to the projects with better returns. As a result, the majority of our dollars for the remainder of the year will be spent on oil related projects.
As Hal mentioned earlier, we plan to increase our capital budget for 2009 to a total of approximately $32 million, and we will continue to manage our capital expenditures closely throughout the year.
Now let’s discuss activity in some of the specific areas. In the Eastern division, which is Michigan, Indiana and Kentucky, we had a very good quarter, with production increasing about 2% compared to Q1. Two rig generating projects, which were both perforation additions were completed during the quarter, and results were double what was forecast with production increasing by about 330 Mcf per day.
Earlier in the year, we restructured the operations areas. That allowed us to reduce management headcount and to shift some of our strong performers to the eastern division. These changes have been very productive steps and the continued integration of the Eastern division properties into BreitBurn, and we have seen significant improvement in our production of surveillance, which effectively increases our daily production.
The last issue I’ll touch on in Eastern is vacuum operations in the Antrim Shale. We have discussed this previously, and believe that allowing vacuum operations will have a meaningful impact on production rates and reserve recovery from the field. This is consistent with the results of vacuum operations that have been in operation for several years in shallow gas fields elsewhere in the U.S.
We expect the application to be filed with the appropriate authorities during the third or fourth quarter of 2009. Once it is filed, however, it will be difficult to predict the timing and certainty of approval. In the Western division, which previously included California, Florida, Wyoming and Texas, as Hal mentioned earlier, Texas was sold at the start of the first quarter.
Our second quarter efforts were focused on cost reductions and implementing several rate generating capital projects. In Florida, two well reactivations have been recently completed. Production is still ramping up, and the wells are producing about 125 barrels of oil a day. In Wyoming, a drilling rig moved through the Hidden Dome Field in late June to drill two new wells and do three well deepening’s.
As of today, two wells have been drilled, and one deepening has been completed. Production from these wells is stabilizing, but the early results are very encouraging. There were also three rate generating projects, one side track, one re-completion, and one fracture stimulation that were done and the results were as expected. These increased production by about 55 barrels of oil per day.
In California, five rig generating projects were completed that added 75 barrels of oil per day, about 50% more than forecast. So, for the last half of 2009, there will be continued strong focus on reducing expenses. They need to continue to come down so they’re more inline with commodity prices, and we’ll continue to high grade our capital projects to ensure the best results possible in today’s environment.
With that, I’ll turn the call over to Jim.
Thank you, Mark. I’d like to cover selected additional financial results for the quarter, then talk briefly about our liquidity position and conclude with a review of key goals for 2009. Let me first discuss some additional financial results for the quarter. We continued to take significant steps to lower general and administrative expenses in this quarter.
G&A expense, excluding unit-based compensation, declined approximately 18% to $5.3 million in the second quarter as compared to $6.4 million in the first quarter of 2009. On a per Boe basis, cash G&A declined to $3.18 per Boe in the second quarter from $4.01 per Boe in the first quarter of 2009.
Our second casual G&A levels were also down significantly, as compared to the fourth quarter of 2008. Fourth quarter 2008 cash G&A was $6.9 million, or $4.06 per Boe. Our cash G&A run rate is down approximately 23% in just two quarters. However, it should be noted that these numbers do not include all of the legal expenses associated with the Quicksilver litigation, the bulk of which we believe to be covered by insurance.
We are currently in discussions with our insurers to expedite reimbursement. We are very pleased with the sequential declines in our quarterly cash G&A, both on a total and per Boe basis, and we’ll continue to work to reduce general and administrative costs. We consider cash G&A for Boe an important metric and we believe our run rates compare very favorably with our closest competitors.
Unit-based compensation expense for the quarter totaled $3.1 million and was flat as compared to the first quarter of 2009 level. Non-cash charges for depletion, depreciation and amortization expense, increased to $53.7 million in the first half of 2009, from $42.8 million in the corresponding 2008 period. The increase in DD&A rates is primarily due to price related reserve division at year end 2008 and their impact on 2009.
Including realized losses of approximately $3.2 million on interest rate swaps, cash interest expense totaled $7.7 million in the second quarter 2009, compared to $5.1 million in the second quarter of 2008, and was below our guidance range for the full year. Please note that our cash interest expense guidance for 2009 assumes all available cash flow after CapEx and interest expense is used to reduce outstanding debt.
Let me now turn to our liquidity position. As Hal mentioned, we are extremely pleased to report that our outstanding borrowing as of June 30, 2009 was $640 million, as compared to $707 million at March 31, 2009. Through strong and consistent operating performance and the monetization of selected out year hedges, we lowered borrowings by $67 million during the quarter.
Subsequent to quarter-end, the sale of the Lazy JL properties generated proceeds of $23 million, all which went directly towards reducing bank borrowings. As of July 31, 2009, our outstanding borrowings were approximately $613 million. In total, we have reduced outstanding debt on our credit facility by $123 million in just the first seven months of the year. This equates to approximately $2.33 per unit in debt reduction.
Cash flow from operations during the first six months ended June 30, 2009 was $141.5 million, including net proceeds from $45.6 million and $25 million from hedge monetization transactions, completed in January and June of 2009. This compares to $134.6 million in the first six months of 2008, when oil and natural gas prices were significantly higher.
Net cash used by investing activities during the first six months of 2009 was $12.1 million, compared to $54.4 million in the first six months of 2008, which reflects our reduced capital spending plan to-date for 2009.
As Hal mentioned, given the recent improvements in oil prices and our improved financial flexibility, we are increasing the pace of our capital plan for the second half of 2009. Our full year 2009 target capital spent has been increased by $8 million to $32 million.
This represents, 45% increase in our mid point guidance range and will help us get investment back towards maintenance capital levels, as we exit the year. Net cash used in financing activities for the first six months of 2009 was $129.7 million, reflecting primarily debt repayments of approximately $100 million, and $28 million of distributions paid in February.
Let me conclude by revisiting some of our key financial goals for 2009. We are pleased with the progress we made in achieving our stated goals for the year. We made measurable G&A reductions and generated substantial cash flows, buoyed by impressive operational performance, our hedge monetization program and non-core asset sales.
Most significantly, we’ve reduced outstanding borrowings considerably. We will continue to pursue general, administrative and operating cost cutting efforts and evaluate capital raising alternatives to enhance liquidity and financial flexibility for the benefit of all of our unitholders.
This concludes our formal remarks. Operator, you may now open the call for questions.
(Operator Instructions) Your first question comes from Michael Blum - Wells Fargo.
Michael Blum - Wells Fargo
Couple of questions, one; can you quantify, if you can you mentioned you think you could see further cost saving efforts both on the OpEx side and G&A? How much further do you think you have to go?
It’s all a function of what commodity prices do. If you can go around and look at our different operating areas, we continue to see cost reductions in the areas that are primarily natural gas. In the oil areas, we’re already seeing those costs level out. So, we still think we’ve got some room to go. It’s hard to quantify it, exactly what the percentage is. I know all of you guys are following rig count and whatnot. We’ve actually seen the U.S. rig count ticking back up. So, all those things impacted.
Michael, on the G&A side, this is HAL We are continuing to look at our operations and look at how we run the business, and we expect to have several more reductions in staff from the G&A point of view and we look at keeping all of the costs in control, looking all our vendors and keeping the costs as low as possible. So, we are continuing to do that, reduce the some additional reductions, but I can’t really give you a percentage at this point?
Michael Blum - Wells Fargo
Second question is just, in terms of the increase in CapEx that you’re going to spend this year; can you give us a sense of, where you’re spending that money and what type of activities? I know you said they’re oil focused, but are you actually getting drill wells or doing re-completion workover? Maybe a little more flavor there. Thanks.
Yes, Michael this is Mark again. The work that we’ll beginning is all either on the West Coast or the East Coast or up in Wyoming. Those are where our properties are that are primarily oil producers, and it’s a mix. It is primarily re-completions and some additional workovers. We have added a little bit of money in there for drilling as well, but it’s essentially all focused at oil producers.
Your next question comes from Richard Roy - Citigroup.
Richard Roy – Citigroup
Just a question on the capital spending program, so you mentioned, because of better crude oil prices, you would increase your program, but that also reflects a certain level of comfort with the October broad-based re-determination?.
Richard, we had what we think is a good first half of the year. Our operations are running very smoothly. We have exceeded our expectations on a number of fronts and are very comfortable with where things are going. While we can never predict what happens and will happen with the borrowing based re-determination, we do think we have value creating projects that we should do in the second half of the year.
We said we want to get back to a maintenance capital spend level, and by increasing the spend in the second half of this year we move much, much closer to that level. So it’s a combination of a lot of factors, Richard and I’d say we are a little more confident about that October re-determination, but you can never be absolutely certain.
Richard Roy – Citigroup
In the context of resuming the distribution, you spoke about the October Permian basin being very important; and certainly without giving a set percentage; but, what kind of levels do you feel comfortable with the resign a distribution?
Richard, it really depends upon where the banks come in and what’s happening with the business at that point. I can’t give you a set level just because that level varies. It really depends based upon how the business is running, what commodity prices are doing at that point in time, and a lot of other factors.
It would be hard for me to say at a set level of borrowing base, would allow us to make distributions, but clear, we are capable of making distributions of today’s borrowing base under the terms of the credit agreement.
Your final question comes from Yves Siegel - Credit Suisse.
Yves Siegel - Credit Suisse
Two questions, one is as you look at the remaining portfolio, any opportunity for further tuning of or rationalization of assets?
We absolutely are looking at that, and we would consider sales of any of our non-core assets. Nothing, other than our position, Indiana, Kentucky, New Albany Shale, that’s probably nothing as clear non-core as our premium based assets were. However, we have received unsolicited offers, and we are talking with several different banks about potential as it sales.
So we’re looking at them, and it really depends, but frankly, we like all of the assets in our portfolio today, and while some maybe attractive as sales candidates, we think there’s a lot of potential in them. So we’re not going to be selling unless we have a good offer and really serves corporate or partnership purpose.
Yves Siegel - Credit Suisse
The follow up question, when you make the decision to increase the budget, what kind of commodity prices are you assuming when you’re looking at committing the incremental dollars?
We run a series of sensitivities, from our base case at $40 oil and $4 natural gas up to the current strip case and as you know, we are heavily hedged, and we do continue to hedge our production as we move forward and so we’re weighing, kind of the $40 case as well as some various sensitivities all the way up to the strip on to make those determinations, and we do have very strong economics on our oil properties with all those sensitivities we’ve been running.
(Operator Instructions) At this time, there are no additional questions in the queue. I’d like to turn the call back over to Mr. Washburn for any additional or closing remarks.
Thanks to all of you this morning for your participation. On behalf of Randy, Mark, Jim, Greg and the entire BreitBurn team, I thank everyone on the call today for their participation.
That concludes today’s conference. We appreciate your participation.
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