BreitBurn Energy Partners L.P. (BBEP) Q3 2009 Earnings Call November 6, 2009 1:00 PM ET
Jim Jackson - CFO
Hal Washburn - Chairman and Co-CEO
Randy Breitenbach - Co-CEO
Mark Pease - COO
Scott Hanold - RBC Capital
Michael Blum - Wells Fargo
Bryan Verona - Vanadium Capital
Welcome to the BreitBurn Energy Partners investor conference call discussing third 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, 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 Friday, November 6 2009. A replay of the call will be accessible until mid night November 13, by dialing 888-203-1112 and entering conference ID 7153194. International callers should dial 719-457-0820. An archive of this call will also be available on the BreitBurn website at www.breitburn.com. I would now like to turn this call over to Mr. Jim Jackson, Chief Financial Officer of BreitBurn. Please go ahead sir.
Thank you and good morning everyone. On with me today are Hal Washburn, BreitBurn's Chairman and Co-Chief Executive Officer, Randy Breitenbach, BreitBurn's Co-Chief Executive Officer and Mark Pease BreitBurn's Chief Operating Officer. Also with us are Greg Brown, our Executive Vice President of Land Legal and Governmental Affairs and our General Counsel. 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 call contains projections, guidance and other forward-looking statements within the meaning of the Federal Securities Laws. All statements other the 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. 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 our 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. These 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 that provides additional information relative to the performance of the Partnership’s business such as our ability to meet our best compliance tests and covenants.
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. We're pleased to report another successful quarter in which the partnership has met or exceeded our annualized 2009 guidance. Our operations team is doing a great job in oil and gas production for the quarter continues to track above the high end of our 2009 guidance range.
From a financial point of view, we continue to reiterate and pursue the goals that we established at the beginning of the year and our financial flexibility continues to improve. Since year-end 2008, we’ve paid down approximately $160 million in debt and we will continue to pursue aggressive debt reduction through internally generated cash flows.
On October 5, 2009, we announced the results of our semi-annual borrowing redetermination. We're extremely pleased that our borrowing base was reaffirmed at $732 million and that we were able to successfully complete redetermination process without any modification to the other terms of our credit agreement. As we move into 2010, our improved liquidity position will allow us the flexibility to increase capital spending to at least maintenance capital levels.
Now let me turn to a few third quarter highlights. Total production for the third quarter was 1.63 million barrels of oil equivalent, which pro forma for the sales Lazy JL Field was virtually flat with the second quarter. Moreover I am pleased to report that even with the sales of Lazy JL, our third quarter production on annualized basis exceeded our 2009 production guidance. Fundamentally the business is performing very well and we're particularly pleased with the ongoing improvement in our Eastern Division.
Cost and expense reduction remain an important name both from an operational and the general and administrative perspective. We continue to pursue cost cutting initiatives and year-to-date LOV and G&A per Boe are well within our guidance. However, it appears that a few of our operating cost components are bottoming out this quarter with some service and materials expenses increasing slightly in response to recent increases in oil prices. Mark will expand on this shortly.
We announced last quarter that we were planning to increase capital spending for the second half of 2009 and we adjusted our CapEx guidance from $20 to $24 million originally to $32 million. As we stated that time, with improved oil prices we will continue to deploy this newly allocated capital, primarily to our oil producing properties. Our balance portfolio mix of oil and gas assets allows us to take advantage of commodity price upswings in either asset group. Mark will elaborate on the latest capital projects in his section.
In August we announced an update to the Quicksilver litigation, which stated that the here in for permanent injunction requested by quicksilver had been postponed from September 2009 to an undetermined future date. Subsequently, the hearing on the permanent injunction and all of quicksilver's other allegations are set for trial in April 2010. We continue to vigorously defend the lawsuit and believe that the allegations against us are without merit.
With that, I'll 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. Let me start by saying we continue to realize the value of our commodity and interest rate derivative instruments as devices for managing commodity price and interest rate volatility. Additionally, they assist the partnership in maintaining stable and predictable cash flows and help support our borrowing base going forward. This quarter as intended, our hedge portfolio mitigated the first commodity prices as compared to the same period a year ago. Including realized gains and losses on commodity derivative instruments, crude oil and natural gas sales totaled $87 million for the thirst quarter of 2009 up just slightly from $86.3 million in the second quarter.
Now, let me provide you with some details of our commodity hedging activity and the impact these derivative instruments have in out third quarter results. Non-cash unrealized losses from commodity derivative instruments for the quarter were $11.6 million and realized gains were $24.3 million. As mentioned, given the recent increases in commodity prices and the Contango in the oil and gas futures curves, we continue to increase and extend our hedge portfolio during the third quarter and throughout October. The partnership supplemented its hedge portfolio in 2010, 2011 and 2013 and extended its oil hedge portfolio into 2014. The new hedges cover approximately 1 million barrels in 2010, 11, 13 and 14 and 8.76 million MMBtus in 2013. Assuming current production levels are held flat, our production is hedged at 87% in 2010, 76% in 2011, 66% in 2012, 49% in 2013. Average annual prices during this period range from $88.35 and $76.82 per barrel for oil, and $8.26 and $6.93 per MMBtu for gas. An updated presentation of the Partnership’s commodity price protection portfolio as of November 6, 2009 will be made available on the Events and Presentations section of the Investor Relations tab on your website.
Going forward, we will continue to use our hedge portfolio as a price protection tool. To-date, it is proven successful in mitigating commodity price volatility, stabilizing revenues and cash flows and supporting our borrowing base. As Hal mentioned earlier, a significant portion of our oil and gas volumes are well protected through the next five years and we will continue to opportunistically evaluate and use derivative instruments.
Now, let me turn the call over to Mark Pease, who will provide you with additional details of our operating performance. Mark?
Thanks, Randy. Operationally we had a very strong third 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 third quarter, the company produced 1.63 million barrels of oil equivalent, which on an annualized basis is above the top end of our guidance range. Earlier this year, we have made some key personnel changes in the Eastern Division, which includes Michigan, Indiana and Kentucky. We continue to see the benefits of these changes, as the Eastern Division again beat their operational targets. And, we've been able to reduce the headcount in the region to a level below where it was when we bought these assets in the fall of 2007.
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 $18.02 per barrel oil equivalent. This is just about the mid point of our yearly guidance of 1675 to 1925 per Boe. Year-to-date LOE, transportation fees and processing fees have averaged $18.03 per Boe, which is right at the mid point of our guidance.
Let me give some additional color on cost trends. We have previously discussed the strong connection of material and service costs to the price of oil and natural gas. Our operating teams continue to put a very, very strong focus on costs and expenses across the company and we have seen considerable benefit from those efforts the past nine months. While are still seeing costs declines in some areas, in other areas and within certain materials and services, costs appear to have bottomed out in the third quarter. A few of our material and service costs have risen slightly compared to the second quarter likely due to rising demand from increased commodity prices.
We are pleased with the team's cost control efforts particularly, as the year-to-date actual operating costs are right in the middle of our guidance range and actual commodity prices which have averaged $57 per barrel of oil and $3.90 per Mcf are significantly higher on an EEB basis than the commodity prices assumed in our guidance range at the beginning of the year which were $40 per barrel of oil and $4 per Mcf flat for 2009. Capital costs for Q3 came in at $7.2 million, which puts capital spending for the first nine months of 2009 at $17.7 million and reflects our increased guidance of $32 million for the full year.
A couple of more comments about our capital program this year. We’ve spent considerably less capital in the first three quarters of 2009 than in 2008 and far less than our 2009 guidance for maintenance capital which we define as the amount of capital required to keep production flat. Nevertheless declines in our production have been minimal. In light of this we are reevaluating our maintenance capital requirements and they will likely be adjusted downward from the current guidance.
Fourth quarter capital spending will ramp up further and on a run rate basis will be closer to what we believe the 2010 maintenance capital level will be. The capital projects completed so far in 2009 have been split about 65% oil and 35% gas. We are fortunate to have a portfolio of assets split fairly evenly between oil and gas, which gives us the flexibility to shift capital to projects with better returns. Given the recovery in oil crisis during the past few months, the majority of our dollars for the remainder of the 2009 will be spent on oil related projects.
We will continue to evaluate the project economics and manage our capital expenditures closely for the remainder of the year. In the Eastern division, we had a very good quarter with production staying relatively flat compared to Q2. (Inaudible) generating Woolworths project and two facility optimization projects were completed toward the end of the quarter and the results were significantly higher than forecast. Production increased by about $1.6 million cubic feet per day compared to a predicted increase of $0.9 million cubic feet per day. The Woolworth projects consisted of three perforation additions, two idle wells that will return to production, one rig completion and one fractured simulation. And the facility optimization project consisted of two line twinings to reduce surface restrictions.
In addition. The automation of the central processing facilities or CPF as we call them was completed in 3Q and now all 70 of our Antrim CPFs are automated. This automation provides remote surveillance and allows a more timely response to well compressor or other facility problems, which effectively increases our daily production. Additionally, automation helps us lower per unit operating cost.
Our current operating cost excluding taxes and processing fees in the Antrim averages about $1.10 per Mcf. The last issue I want to touch on regarding our Eastern division is waxing operations on the Antrim Shale. As we said in the past we believe that allowing vacuum operations will have a meaningful impact on production rates and reserve recovery for the Antrim field. This is consistent with the results of vacuum operations that have been in operation for several years and shallow gas fields elsewhere in the US. In the third quarter of this year, BreitBurn along with other components of vacuum operations filed matching applications with the Michigan Public Service Commission requesting approval for vacuum operations.
However, several operators have intervened in the process and have expressed opposition to vacuum compression in the area. The timeline has been established for resolving the issue over the next 15 months. The judge will enter a decision to the Michigan Public Service Commission by January 31, 2011, who in turn is respected to render a decision by mid 2011. This timeline is longer than we would have preferred but there is now a clear path to getting a decision on this issue.
In the western division, which includes California, Florida and Wyoming our third quarter efforts were focused on drilling and optimization projects in Wyoming and continued work on facility projects in California. 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.
The two drilled wells and two to three deepening’s were completed during the third quarter. We also performed one producer optimization in Wyoming. The combined production from Wyoming drilling and optimization projects is over 190 barrels oil a day. About 50% higher than our predicted rate of 120 barrels a day. In California, several facility projects to improve infrastructure and one to generate electricity from stranded gas or continuing and expected to be completed during the fourth quarter in 2009.
In Florida, we continue to optimize our artificial lift insulations by resizing and upgrading our submersible pumps. Two wells were optimized during the quarter. So, going forward our operations team will continue the strong focus on controlling cost. And we will continue to evaluate project economics in light of changing commodity prices and deploy capital or generate the best returns.
With that I will turn the call over to Jim.
Thank you, Mark. Let me start with a few comments on the financial goals we set out for the year. And then review some of the more specific results for the quarter and our outlook through the end of the year.
Recall, we entered the year with almost a singular focus on liquidity. We are pleased that with the benefit of our third consecutive strong quarter, we have made some substantial progress towards our goals of funding our operations, capital expenditures, interest cost and debt reduction through internally generated means.
Of course it all starts with production and as Hal and Mark pointed we are turning at the high end of our production guidance range year-to-date and essentially help production flat quarter-to-quarter despite the conservative CapEx program we had in place for the first nine months of the year and the sale of our Texas assets.
Revenue, including realized gains and losses on commodity derivative instruments but excluding the effects of hedge monetizations, rose 1% in the third quarter to $87 million from $86.3 million in the second quarter. Better than expected differentials contributed to our strong financial performance in the quarter. Natural gas differentials came in exactly as we had guided right around 101% of Henry Hub but more importantly however oil differentials were approximately 91% of WTI versus our guidance range of 84% to 86%. These improved oil differentials contributed approximately $2.7 million of additional revenue during the quarter.
As Mark mentioned, lease operating expenses, transportation fees and processing fees which are our control operating costs came in at just under $30 million or approximately $18 per boe which is right on the mid point of our guidance. Additionally we continue to pursue our cost reduction efforts on the G&A side. General and administrative expenses excluding unit based compensation expense was $5.8 million in the third quarter versus $5.3 million in the second quarter. On a per boe basis cash and G&A was $3.59 per boe in the third quarter.
Cash G&A in the quarter included approximately $300,000 for professional services fees including legal expenses that we had not originally budgeted for. Despite these unexpected expenses year-to-date we are so well within our guidance range.
Adjusted EBITDA was $48.4 million in the third quarter as compared to $50.8 million in the previous quarter. On an annualized and year to date basis, these results are currently at the high end of our guidance range.
Not surprisingly, given year-to-date EBITDA performance, we are reaffirming our full year EBITDA guidance and should finish the year near the high end of our $178 million to $196 million guidance range. Production and property taxes totaled $4.4 million in the third quarter as compared to $4.2 million in the second quarter. This increase in taxes was principally due to higher realized oil prices and differentials on the quarter offset slightly by lower natural gas prices.
Net interest and other financing costs excluding realized and unrealized gains and losses on interest rate swaps for the third quarter, were $4.5 million compared to $5.4 million in the second quarter including realized losses of approximately $3.4 million on interest rates swaps, cash interest expense, totaled $7.1 million in the third quarter of 2009 compared to $7.7 million in the second quarter.
Year-to-date cash interest expense continues to crack below the low end of our 2009 guidance range given the success of our debt reduction efforts this year. We recorded a net loss in the third quarter of $5.4 million or $0.10 per limited partnership unit. This net loss included a $5.5 million loss on the sale of assets recorded in conjunction with the sale of our Texas assets in July.
Let me now turn to our liquidity position. As mentioned, we reduced outstanding borrowings by $55 million in the quarter from $640 million at June 30, to $585 million at September 30. Through consistent operating performance, the optimization of our capital spending, continued focus on expense reductions and opportunistic hedge monetization and asset sales, we have been able to pay down approximately $160 million in debt, since year end 2008. And as of October 31, out total debt outstanding was $576 million, which represents approximate debt reduction, $3 per unit since the beginning of the year.
I am pleased to point out, that we were able to accomplish this debt reduction, without a highly dilutive equity offering at the strip prices without incurring high cost long term debt with restricted financial covenants, without modifying the terms of our existing credit facility which would no doubt at what the higher cost and without selling or joint venturing any core assets. We are in a much improved position financially as we move closer to 2010. However, while we have made significant progress from a liquidity point of view we still remain subject to the restricted provisions of our credit facility, which include provisions limiting our ability to make certain restricted payments including distributions.
As such, we will continue focusing on our goals of funding our operations, capital expenditures interest costs and debt reduction through internally generated means.
This concludes our formal remarks, operator you may now open the call for questions.
Thank you. The question and answer session will be conducted electronically. (Operator Instructions). We will take our first question from Scott Hanold from RBC Capital.
Scott Hanold - RBC Capital
When you guys look at your production obviously tell then they are pretty good and can you attribute some of that to you know obviously having a lower drilling activity and having a lot of those called the [flush] production run off and serve them in more of a steady decline and it kind of ties it in with what do you all think your real maintenance CapEx number is at this point. And is it serving this $10 million type of range I guess your fourth quarter numbers sort of implies you are going to spend along about $10 million to $15 million which it seemed to be enough to start to get production to grow?
Let me make a couple of comments about our assets. First of all, I think from watching us, we have a very low base decline on our assets anyway. So, that certainly helps on the maintenance CapEx side. When you look at what we have done so far this year and the way we have been able to keep production up, we have been paying a tremendous amount of detail to the operations up in the Michigan area. We have done a lot of things up there, particularly that has been facilitated by having some new management there. And I just can’t emphasize how important that’s been to us.
But we are paying our attention to a lot of details just a lot of hate to call it blocking and tackling, but that’s really what it is, just taking care of our business and we have been able to do some very efficient work over there. Some very efficient facility deep bottlenecks and those things have all helped that production come up. So, I think those are probably the biggest reasons that production has stayed where it is. Regarding what maintenance capital is, we are still working through that number, and we’ll provide that guidance later, but it's certainly going to go down from the numbers that we have given in the past.
Scott Hanold - RBC Capital
And you had mentioned some of the effects like, it was against your budget for full year that was $32 million, you spend it more roughly $18 million year-to-date deal spend somewhere in that $12.5 million range in the fourth quarter is that the way you are seeing it right now?
We think we are going to track right on what we guided for revised budget last quarter, so $32 million for the year.
Scott Hanold - RBC Capital
Okay and that’s kind of the run rate, that you are going to start to lead into ’10 with?
Scott Hanold - RBC Capital
Okay. Alright and talking a little bit about what are the appropriate debt levels you all see as far as when you are going to feel comfortable seeing the distribution and regarding the covenants that would be restrictive to paying distribution at this point, is there anything that would hamper you right now or theoretically would want to, because I thought the biggest one was if you are 90% drawn on your revolver which at this point I don’t believe you are, right?
Correct, Scot its Jim, let me answer the first question. We’ve I think been reasonably clear that we’d really like to see a path through 2.5 times debt to LTM EBITDA, and that would not necessarily be a sufficient condition, but we are [staying] in the distribution but we will have to get visibility on that and I think we are very much on track to move to may be through that goal in 2010. With respect to the covenants and not to get into too much detail, but effectively there are two principle restricted payment tests we need to satisfy the first says we can’t be more than 90% drawn on our borrowing base, pro forma, having into distribution. So you should certainly calculate that in your model. And secondly we have another restricted payment set that says at any given time, pro forma for having drawn down another 10% of the borrowing base will remain in compliance with all the other covenants in the documents, and what that effectively does is if you look at our maintenance covenant which is 3.5 times debt to EBITDA, we would need to be able to borrow 10% more than we have borrowed, well 10% more of the borrowing base than we have borrowed at any given time that remained in compliance with that. So, those are the two real material points, and in any given quarter one of them is more operative than the other.
Scott Hanold - RBC Capital
Okay got it thanks.
We’ll take our next question from Michael Blum of Wells Fargo.
Michael Blum - Wells Fargo
Hi, my questions were asked and answered. Thanks.
We’ll take our next question from Bryan Verona of Vanadium Capital.
Bryan Verona - Vanadium Capital
Hi quick question with respect to the 8-K from November 4th, specifically relating to the rephrasing of restricted stock awards. What is the anticipated charge either in the fourth quarter or later, relating to this re-pricing? And secondly from detail with respect to a number of sold units that we were re-priced? And then also could you sort of talk about the board support for that change in that retention plan? Thank you.
Sure this is Hal. Well first up we didn’t re-price any restricted units, so there won’t be any charge visibly change to multiply our table. So there is no charge at all, I believe that there is 700,000 units, approximately 700,000 units that were affected. And it obviously had full support of the board in fact the unanimous support of the board are not changed
Bryan Verona - Vanadium Capital
The state of purpose was retention correct? Is that again highly unusual on this with 10% employment any talks about the necessity to do it other than what you said publicly?
It was pretty (inaudible)
Bryan Verona - Vanadium Capital
Okay thank you very much.
(Operator Instructions). And at this time, we will turn the call back over to Mr. Jackson for any closing or additional remarks.
Operator at this point we have no further remarks, we appreciate everyone joining and on behalf of Hal, Randy, Mark and Greg and the entire BreitBurn team here. Thanks very much for your participation, and that will be all for today.
That concludes today’s conference, thank you for your participation.
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