BreitBurn Energy Partners Q4 2008 Earnings Call Transcript

Mar. 2.09 | About: Breitburn Energy (BBEPQ)

BreitBurn Energy Partners (BBEP) Q4 2008 Earnings Call March 2, 2009 5:00 PM ET

Executives

Hal Washburn – Co-CEO

Jim Jackson – EVP & CFO

Randy Breitenbach – Co-CEO

Mark Pease – COO

Larry Smith - Controller

Analysts

John Kang - RBC Capital Markets

Jack Ripstein – Potrero Capital

[Michael Shulton – Ingalls and Snyder]

Operator

Welcome to the BreitBurn Energy Partners investor conference call discussing fourth quarter and year-end 2008 results. The company’s news release made earlier today is available from its website at www.breitburn.com. (Operator Instructions) A replay of the call will be accessible until midnight March 9, by dialing 888-203-1112 and entering a conference ID of 7668834. International callers should dial 719-457-0820. An archive of the call will be also available on the BreitBurn website at www.breitburn.com.

At this time I would like to turn the conference over to Jim Jackson, Chief Financial Officer of BreitBurn; please go ahead.

Jim Jackson

Good afternoon everyone, here with me to present are Hal Washburn and Randy Breitenbach, BreitBurn’s Co- Chief Executive Officers; and Mark Pease, BreitBurn’s Chief Operating Officer. Also with us is Larry Smith, our Controller.

After our formal remarks we will open the call for questions from security analysts and portfolio managers. 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 federal securities laws. All statements other then statements of historical fact 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 simply set forth our best estimates today based upon our current expectations about future developments, based on numerous 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 relevant to forward-looking information section of our today’s press 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 which was filed earlier today and our Quarterly Reports on Form 10-Q and our current reports of Form 8-K and 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 publically any forward-looking statements to reflect new information or events. Additionally during the course of today’s discussion management will refer to terms such adjusted EBITDA, and distributable cash flow which are non-GAAP financial measures as significant performance metrics used by company management to indicate among other things, the cash distribution the company expects to pay to unit holders.

Specifically these non-GAAP financial measures indicate to investors whether or not the company is generating cash flow at a level that can sustain or support an increase in its quarterly distribution rates. Please note that these financial measures which are used throughout the investment community for publically traded partnerships like BreitBurn are reconciled to the most directly comparable GAAP measures in the earnings press release made earlier this afternoon and posted on the partnership’s website.

With that let me turn the call over to Hal.

Hal Washburn

Thank you Jim and welcome everyone. In 2008, it was a very productive but challenging year for the partnership. Our principle operating focus was the integration and development of the significant oil and gas acquisitions we completed in 2007 and we are pleased with our 2008 results were generally in line with our full year guidance despite the economic and other headwinds which arose unexpectedly in the second of 2008.

In addition to the progress we made growing the business during the year, the partnership also repurchased Provident Energy trust interest in BreitBurn and as part of that transaction granted unit holders a new right to vote for the election of directors. We believe this was one of our most significant accomplishments on behalf of our unit holders in 2008.

In light of current oil and natural gas prices and the state of the financing capital markets we expect 2009 to be a year of increased internal focus and decreased acquisition activity, however as the commodity and financial markets eventually stabilize we intend to increase our attention towards acquisition opportunities consistent with our core long-term strategy.

Our goal in 2009 is to fund our operations, capital expenditures, interest payments, and distributions to unit holders from our internally generated cash flow and to preserve financial flexibility and liquidity to maintain our assets and operations in anticipation of future improvement in the overall economic environment, commodity prices, and the financial market.

In response to the rapid and substantial decline in oil and natural gas prices, the outlook for the broader economy and the ongoing turmoil in the financing markets, we have elected to significantly reduce our capital expenditures and drilling activity in 2009. Our capital program is expected to be approximately $20 million in 2009 compared to approximately $129 million in 2008 and $27 million in 2007.

This level is in line with our assumption of $40 oil and $5 gas and our expected cash flow from operations which is anticipated to be lower in 2009. We do however have the flexibility to adjust our capital program in response to commodity prices rebounding or declining further. We are prioritizing our capital projects and concentrating on those promising the greatest return on invested dollars.

Nevertheless due to the low production decline nature of our assets we expect our 2009 production to be between 6.1 and 6.5 million Boe. As we and the balance of the industry prepare for a challenging 2009 we’re more focused then ever on our goals to achieve a balance of liquidity, cash flow, and growth.

If oil and natural gas prices improve in 2009 we subsequently increase the scope of our capital or acquisition program we would expect an increase in our production rate. We are also very focused on substantially reducing operating, general, and administrative costs in 2009. Our focus on reducing costs is included but is not limited to a realignment of certain divisional operating roles to consolidate responsibilities, negotiated reductions in fees and expenses from third party service providers, as well as planned personnel reductions in both operations and administrative functions.

We are finalizing our detailed guidance for 2009 and will release this guidance later this month. Turning now to a review of the changes in the economic landscape and their impact on BreitBurn’s fourth quarter and year end results, crude oil prices fluctuated widely during 2008 from a high of $145 per barrel in July, to a low of $30 per barrel in December and in the first two months of 2009 averaged approximately $40 per barrel.

Similarly natural gas prices peaked at $13.58 per MMBtu in July of last year, sinking to $5.29 per MMBtu in December and in the first two months of 2009 ranged between about $4 and $6 per MMBtu. The commodity price decline has a material impact on our operating performance even though we have strategically hedged approximately 85% of our current production at oil and gas prices above $70 and $8 respectively through this commodity price volatility.

We have also done the same thing for future year’s production. Hedging remains an important part of our strategy to reduce cash flow volatility. Randy will discuss our hedging strategy in depth in a moment. The precipitous commodity price decline effected our estimates proved reserves also. As of December 31, 2008 our estimated proved reserves were 103.6 MMBoe or a million Boe, 27% lower then our 142.2 MMBoe as of December 31, 2007 primarily due to lower year end commodity prices.

For example the price of oil on December 31, 2008 was approximately $45 per barrel which is less then half of the approximately $96 per barrel price on the last day of 2007 when BreitBurn’s proved reserves were last calculated. Mark will discuss the details in a few minutes.

In addition to the sharp declines in oil and gas prices deterioration of the credit markets intensified and accelerated during the latter part of 2008 putting severe constraints on the ability of companies like our to access capital in order to grow. Fortunately we have the flexibility in our capital program to scale it up or down in response to changing market conditions.

On February 13 we paid a cash distribution of $0.52 per unit or approximately $27.4 million to our common unit holders of record as of the close of business on February 9, 2009. We have managed BreitBurn for more then two decades and have successfully navigated several low oil and gas price cycles. We have learned valuable lessons from those experiences and as always we will focus on running all areas of our company as efficiently as possible.

With that let me ask Randy to briefly cover some of the operating highlights from our fourth quarter and full year ended December 30, 2008.

Randy Breitenbach

Thank you Hal and welcome everyone to this afternoon’s call, during the fourth quarter of 2008 our production increased 22% relative to fourth quarter 2007. Oil and NGL production was 767,000 Boe compared to 738,000 Boe for those periods respectively and natural gas production was 5.53 Bcf compared to 3.9 Bcf in the fourth quarter of 2007

Although year end commodity prices were down significantly from the prior year end period given our extensive hedging position realized prices for the period were comparable. Realized natural gas prices for the fourth quarter of 2008 averaged $8.04 per Mcf compared with $7.51 per Mcf in the fourth quarter of 2007 and realized crude oil and liquids prices averaged $60.81 per Boe compared with $62.59 per Boe in the comparable quarter a year ago.

These realizations include realized gains and losses on derivative instruments. Again although commodity prices were down appreciably, oil and natural gas sales revenues including realized gains and losses on derivatives instruments were up 32% at $96.3 million in the fourth quarter of 2008 and $73.2 million in the fourth quarter of 2007.

Adjusted EBITDA also increased 17% to $50.9 million in the fourth quarter of 2008 from the corresponding prior year end period. Per unit production expenses which include lease operating expenses, production and property taxes, and processing fees declined to $19.21 per Boe from $19.70 in the year ago quarter. Given the current market conditions management has been working hard to push expenses down to levels commensurate with low commodity prices.

There is an expected lag between the drop in prices and lower expenses as would be expected. Noncash charges for depletion, depreciation, and amortization expense increased to $115.7 million in the fourth quarter of 2008 from $15.7 million in the corresponding 2007 period. This increase is primarily due to a fourth quarter charge of $86.4 million for price related DD&A adjustments and impairments related to certain of our long lived oil and gas assets.

Low commodity prices related reserve cuts in the high price environment in which certain of our fields were acquired were all contributing factors. Increased produced volumes from our 2007 acquisition also contributed to the year over year increase in DD&A. Net income was up significantly for the period to $251 million or $4.65 per diluted limited partner unit reflecting $331.4 million in noncash unrealized gains attributable to the change in fair value of the partnership derivative financial instruments.

This compares to a net loss of $47.1 million in 2007 or a loss of $0.86 per diluted limited partner unit including unrealized losses of $63.6 million. Distributable cash flow was $29 million, 18% lower then the fourth quarter 2007 primarily due to higher interest expense and higher maintenance capital expenditures. Oil and gas capital expenditures totaled $31.8 million in the fourth quarter of 2008 and were in line with expectations.

Now let me provide you with some details of our commodity hedging activity and the impact these derivative instruments had on our fourth quarter results. We had noncash unrealized gains from commodity derivative instruments and noncash unrealized losses from interest rate derivative instruments during the fourth quarter of 2008. To be specific noncash unrealized gains of $346.4 million for the fourth quarter of 2008 reflect the impact that lower crude oil and natural gas futures prices had on changes in the fair values of our commodity derivative instruments related to the expected sales of our future production through 2012.

This was partially offset by noncash unrealized losses of $15.0 million for the fourth quarter of 2008 reflecting the impact that changing interest rates had on changes in the fair value of our interest rate swaps during the period. As you know 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 cash flows for operating activities, acquisitions, capital expenditures, interest expense, and distribution to unit holders.

To be clear, unrealized losses or gains do not effect adjusted EBITDA and cash flow from operations or the partnership’s ability to pay its cash distribution. Given the dramatic fall in prices EDP’s hedging strategy to provide significant price support and to help mitigate commodity price volatility and protect revenues, is proving very beneficial.

Assuming current production levels are held flat through 2012 oil and gas volumes are very well protected with hedges in place for approximately 85% of our production in 2009 and 2010 and 70% of our production in 2011 and 2012. We are fortunate to have a strong hedging position that locks in strong cash flows well into the future.

Now let me turn the call over to Mark Pease who will provide you with additional details of our operating performance.

Mark Pease

Thanks Randy, let me start with key full year comparisons. During 2008 we ramped up activity from the acquisitions we made in 2007. Our daily production for 2008 averaged 18,605 barrels of oil equivalent per day which was 126% increase from a year earlier. While we were within guidance for the full year, our fourth quarter was below our expectations primarily due to the previously discussed delays in obtaining drilling permits and pipeline easements in Michigan, surface facility restrictions in Michigan, and the sharp cutback in activity across the company during the fourth quarter.

We have made significant progress working through the permitting and easement delays and I’ll describe this more fully in a couple of minutes. Additionally we are working to address the facility restrictions that our new volumes have encountered in Michigan. Production over the full year 2008 was 55% natural gas, 43% oil, and 2% natural gas liquids. There are a number of company operational records that were set during 2008.

Drilling activity was increased and we reached the peak of eight drilling rigs running in August of 2008, 131 gross development wells were drilled during the year. This compares to 24 wells drilled in 2007. Of the 131 wells drilled 116 were in Michigan. Capital expenditures increased from $27.6 million in 2007 to about $129 million in 2008. The increase in spending was mostly driven by the drilling activity in Michigan.

As planned when we made the acquisitions in 2007 we have significantly increased the activity level on the acquired properties in order to capture the existing opportunities that were recognized. Hal mentioned earlier that the fourth quarter was challenging in a number of areas. On the operational side we were faced with service and materials costs that had been driven up by months of strong commodity prices.

When these costs were aligned with the dramatic drop in commodity prices that occurred in the last few months of the year, it was clear that the capital work program outlined earlier in the year needed to be changed and that critical attention should be placed on our cost structure. As discussed during the third quarter earnings call, a strong focus was put on both reducing our capital expenditures and in working with our service and material providers to lower costs.

We worked swiftly during the quarter to do both. Peak rig count in the fourth quarter was five rigs as compared to eight rigs in the third quarter and we exited 2008 with no rigs running. Capital expenditures dropped from $52.8 million in the third quarter to $31.8 million in the fourth quarter. We realized meaningful reductions in the cost of services and materials by the end of the fourth quarter. Some examples are casing prices which had approximately doubled in the first three quarters of 2008 went down 30% to 40% during the fourth quarter.

Fuel costs which had increased 60% to 90% during the first three quarters dropped to about 50% in Q4 and rig costs which had gone up 15% to 25% in the first three quarters dropped between 5% and 20% during the fourth quarter. Costs are an area of our business where we will continue to put a lot of focus and effort. So for the fourth quarter the company drilled or recompleted a total of 23 wells, 17 of those were in Michigan, three were in California, one in Wyoming, and two in Texas.

This compares to 81 new drilled wells and recompletions during the third quarter. For the full year 172 new drilled wells and recompletions were completed reflecting the significant increase in activity that was planned at the start of the year. Of the 172 projects completed, 128 of them were in Michigan. We talked in previous earnings calls this year about the challenge we’ve had getting permits in Michigan both for drilling new wells and for laying the flow lines to connect them for production.

Very good progress has been made in both these areas. We now have a sufficient inventory of permits in hand for the drilling and rig completion activity planned in our 2009 program and most of the activity planned for 2010. Regarding oil connections, at the end of the third quarter of 2008 there were 53 wells shut in waiting on pipeline connections. By the end of the fourth quarter we had reduced that number to 23 wells and as of today, there are 11 wells that are shut in waiting on connections.

Now let’s talk about the operating results for the fourth quarter and for the full year. Lease operating expense excluding production and property taxes for the fourth quarter came in at $15.10 per Boe which was within our guidance range of $14.00 per Boe to $15.40 per Boe and was a significant reduction from the third quarter level of $19.36 per Boe. This shows that progress has been made but more work needs to be done and it will be a continued area of our focus.

For the full year lease operating expenses excluding production and property taxes came in at $15.95 per Boe which is about 3% above the top end of our guidance range of $14.00 to $15.40 per Boe. Realized oil and natural gas prices for the first three quarters of 2008 were significantly higher then those used in our guidance forecast. When you factor in the upward pressure of those higher commodity prices put on materials and service costs, our operating team did an excellent job staying generally in line with our guidance and I’m proud of what they accomplished.

Now let’s shift and talk about reserves, BreitBurn’s total estimated proved oil and gas reserves as of December 31, 2008 were 103.6 million barrels of oil equivalent under the current Securities and Exchange or SEC rules. Standardized measure of net future cash flows discounted at 10% from the production of these reserves is approximately $592 million using prices and costs in effect as of the date such estimates were made.

These prices and costs are held constant throughout the life of the properties. Of the total estimated proved reserves 75% were natural gas, 92% were classified as proved developed, and 78% were located in Michigan, 12% in California, 6% in Wyoming, and the remaining 4% was located in Florida, Texas, Indiana, and Kentucky. For 2008 production for the partnership was approximately 6.8 million barrels of oil equivalent.

During 2008 the partnership added proved reserves totaling 8.2 million barrels of oil equivalent from additions. This equates to 121% of the partnership’s production for the year. Of the 8.2 million barrels added the majority, 6.7 million barrels of oil equivalent were additions primarily in the Michigan Antrim trend where the partnership drilled 116 wells.

The 8.2 million barrels of reserve additions were offset by negative economic and technical revisions of 4.5 million barrels of oil equivalent. Approximately 94% of these reductions were due to economic, price, and cost revisions resulting from using December 31, 2008 prices of $44.60 per barrel of oil and $5.71 per MMBtu of gas as compared to December 31, 2007 prices of $95.95 per barrel of oil and $6.80 per MMBtu of gas.

Under current SEC rules third party reserve auditors use year end commodity prices and the prior 12-month average for leased operating expenses. The sharp drop in oil and gas prices during the last few months of 2008 created a scenario for reserve determination purposes that combined high lease operating expenses consistent with the high commodity prices during the majority of 2008 with the very low year end oil and gas prices.

Management believes that this combination produces very conservative reserve estimates. In late December 2008 the SEC released its final rules on modernization of oil and gas reporting that will go into effect for the 2009 reporting year. The new rule provides that prices used to calculate year end reserves are based on the average of the prices at the beginning of each calendar month of the year as opposed to the price on the last day of the year.

Management believes that this price methodology more accurately matches expenses to the commodity price environment that was realized. Using this pricing methodology for the 2008 reporting year, BreitBurn’s reserves would have been 140 million barrels of oil equivalent based on prices of approximately $102 per barrel of oil and $9.00 per MMBtu of gas.

So looking forward into 2009 Hal mentioned earlier that if current commodity price levels we are forecasting the capital budget to be approximately $20 million. This will be a substantial reduction compared to 2008. We intend to tie expenditures with expected cash flow so the capital budget could change if actual commodity prices differ from our budgeted prices.

What won’t change is the strong focus we currently have on reducing costs and optimizing our operations to align them with current commodity prices. I’ll now turn the call over to Jim who will discuss the fourth quarter’s financial results and introduce our guidance for 2009.

Jim Jackson

Thank you Mark and thanks everyone for joining, I’d like to go through select additional financial results for the quarter, provide details on our liquidity position, and introduce preliminary guidance for 2009.

First let me discuss G&A, G&A expense for the fourth quarter totaled $10.6 million and included $1.7 million for unit based incentive compensation expense. So G&A expenses for the quarter excluding unit based compensation expense were approximately $9 million which was $1.9 million higher then the fourth quarter of 2007. This increase is principally the result of higher then expected legal and other professional services fees.

For the full year our G&A expense totaled $43.4 million in 2008 compared to $30.2 million in 2007. These amounts included $6.5 million and $12.8 million respectively in unit based compensation expense. This decline in unit based compensation is attributable to a decrease in the price of our common units during the year.

Excluding unit based compensation expense our G&A for all of 2008 was $37 million which was at the low end of our guidance range of $37 to $39 million for the year. Cash interest expense including realized losses of approximately $1.1 million on interest rate swaps totaled $9.8 million in the fourth quarter of 2008 compared to $2.3 million in the fourth quarter of 2007.

This increase is due to a higher average long-term debt balance in the fourth quarter of 2008. At December 31, 2008 we had $736 million in outstanding borrowings under our credit facility compared to $370.4 million at the same time last year. For the full year 2008 cash interest expense including realized gains and losses on interest rate swaps, totaled $29.3 million compared to $3.5 million in the prior year.

Our 2008 cash interest expense was within our most recent guidance which was updated in June for the Provident repurchase financing. Our cash flow from operations during 2008 was $226.7 million up from $60.1 million in the corresponding year ago period reflecting a full year for the four major acquisitions made in 2007 as well as higher overall commodity prices compared with 2007.

Net cash used by investing activities during 2008 was $141 million compared to slightly more then $1 billion in 2007. Ninety-three percent was spent on capital expenditures primarily on drilling and completion activities including $83 million in Michigan, Indiana, and Kentucky. Approximately $20 million was spent in California, $11 million each in Wyoming and Florida, and $3 million was spent in Texas. An additional $3 million was spent on non oil and gas expenditures.

The remaining $10 million was used to repurchase Provident’s general partner interest in the partnership. As Hal and Mark mentioned, we are significantly reducing our capital spending plans for 2009 in response to market conditions. Net cash used in financing activities for 2008 was $89 million and for the full year we paid total distribution to unit holders of $121.3 million.

As I mentioned as of December 31, 2008 we had outstanding borrowings under our credit facility of $736 million. Our borrowing base was increased in June 2008 to $900 million and was last affirmed in October. As of February 27 we had approximately $714 million in borrowings outstanding under our credit facility. Our next semiannual redetermination is scheduled for April, 2009.

During 2008 we borrowed $803 million and repaid $437 million under our credit facility, $336.2 million of the borrowings were used to repurchase Provident’s limited partner interest and general partner interest in the partnership and front $1.2 million of transaction costs. Let me move on to our preliminary guidance for 2009 which we announced in today’s earnings release.

Please note that we expect to provide more detailed guidance similar to the level of detail in our 2008 guidance later this month. Our current 2008 capital budget is approximately $20 million. Nonetheless due to low production decline nature of our assets we expect our 2009 production to be between 6.1 and 6.5 million Boe. As oil and natural gas prices improve or if operating and development costs decline and we elect to increase the scope of our capital program based on these or other factors, we would expect an increase in our anticipated 2009 production rate and aggregate volume.

This concludes our formal remarks. We are now ready for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of John Kang - RBC Capital Markets

John Kang - RBC Capital Markets

I guess the first question that comes to mind with your new CapEx program is what is your thoughts on maintenance CapEx and your thoughts on how you’ll fit your distribution for 2009, I was just going through the math and if I use $20 million as the CapEx number then you should have plenty to pay the $0.52. I’m just wondering can you do that or do you have to assume a certain level of maintenance CapEx when you figure out your distributable cash flow.

Hal Washburn

We do assume a certain amount of maintenance CapEx each year whether we spend it or not and so as the year goes on we will be tracking that. Hopefully prices will come up or service costs will come down and we’ll be able to increase our capital budget for the year. But we aren’t looking at $20 million as being a maintenance CapEx number, we’re really tying that to what we believe to be the right number given today’s oil and gas prices and today’s service costs.

John Kang - RBC Capital Markets

I guess as a follow-up should we assume its somewhat similar to what you’ve said in the past, the maintenance CapEx.

Hal Washburn

Yes I think so.

Jim Jackson

I think as a working assumption you should continue to use what we have said historically about our maintenance CapEx assumption.

John Kang - RBC Capital Markets

Do you have any early indications or estimates on your expectations for your borrowing base redetermination or is it just too early to tell.

Jim Jackson

At this point its too early to tell. That’s scheduled for an April 1 redetermination and our lead agent is doing their initial work. They continue to do that now so that process is close to I guess formally beginning but it has not started, its not been rolled out as far as we know to the broader bank group.

John Kang - RBC Capital Markets

And you don’t have an indication of what there price spec they may be using I guess.

Jim Jackson

Well every bank will ultimately use its own deck, I think frankly I think Wells in terms of determining their recommendation is, may still be considering that but if they have settled on one I don’t know, I don’t think we know what it is at this point.

Operator

Your next question comes from the line of Jack Ripstein – Potrero Capital

Jack Ripstein – Potrero Capital

Can you give us some feel for your distribution going forward, if I look at the prior quarter, this quarter you just reported, it looks like out of regular cash flows the distribution wouldn’t be sustainable, obviously you’ve got some room under your borrowing to make those decision, going forward can you give us a snapshot of what the cash on the balance sheet looks like and how that fits with a distribution looking forward and your borrowing base.

Jim Jackson

Given what we’re now looking at in terms of the capital program for 2009 which I think as Hal mentioned we’re looking to upscale throughout the year in anticipation hopefully of prices improving or costs coming down. Just based on that modest capital program, barring any other factors or restrictions we would see the ability to fund our operations, our business, distributions, and maybe even pay down some debt.

I think the real question is what’s the right view of long-term oil prices and ultimately how do we bake in a fully burdened maintenance CapEx assumption into a distribution policy and I think we’re still working on that.

Hal Washburn

One other point and we’ve made this, we are taking a long-term view of this business and what that means is as far as distribution policy is that we will live with short-term situations that aren’t optimal or that are better. In other words if we have a very high ratio of distributable cash flow to our distributions for our quarter we won’t necessarily raise our distributions. Likewise we would be willing to live with a sub 1.0 coverage ratio for a short period of time if we believe that we’re living in a market where either the prices have come down much faster then costs have come down or we don’t see the short-term prices reflecting long-term nature of our business.

Jack Ripstein – Potrero Capital

It sounds like you’re very comfortable then with you current debt and capacity and whatnot, and from that standpoint can you give me some idea of what would cause discomfort at this point, what would be the worst case scenario in terms of, it looks like you’re within your leverage ratios although one could construct scenarios where that could fall out of whack. Where are you in terms of comfort with the debt load and how that’s serviceable vis-a-vie your lenders.

Jim Jackson

I think certainly given the backdrop in the financial markets, anybody who has leverage probably feels like they have too much so I think we would look and we have been thinking about for some time opportunities to either manage the outstanding debt or alternatively reduce it or do something constructive there. I think we’ve always said we’d like to run the business probably with less debt on it. Those being in total terms and in relative terms and we have on it today, so I think 2009 will be an interesting year for us and everybody else in terms of working on the balance sheet.

Operator

Your next question is a follow-up from the line of John Kang - RBC Capital Markets

John Kang - RBC Capital Markets

Just a question about your CapEx with the $20 million would you be able to give us a little more color on where that may be spent and is that some bare bones minimum you think you need to spend to keep Michigan kind of going at its current, not run rate, but you know obviously when you purchased the acquisition there wasn’t enough capital spent on the properties, is $20 million enough for all the projects that you, is it a comfortable range for you.

Mark Pease

The $20 million splits about 50-50 between what we call mandatory capital and those are things that we feel like we need to do either from a regulatory standpoint or facilities that need to have upgrades and need to be repaired so its not what we would call rate generating capital and that’s in all our properties across the US. The other half of that is going into rate generating opportunities and again its spread out, if you just look at it on a per reserves basis if you will, its spread out proportionately to our reserves so most of that is going to Michigan.

But what we try to do is put it in there, is where we can get the most bang for the buck so we looked at the projects that had robust economics and very low price environments and that’s where we put the money. So we’ve obviously got a lot of other projects that we could do, projects that we could do at current prices and if prices improve somewhat, we’ve got significant number of projects that we can add to that.

Hal Washburn

We’ve seen that there’s been some pressure on prices as well and I think there’s probably and likely some benefit from us actually pulling back our capital plan until things have kind of right sized with commodity prices. And so I think just waiting a few months as you’ve seen from what Mark has said we’ve seen significant cuts in costs and so obviously those cuts will respond very favorably in our economics if we wait.

John Kang - RBC Capital Markets

And let’s say you were to start in earnest, let’s say second half to really ramp up CapEx would that have any impact to 2009 or would it be more a 2010 [inaudible] pretty severe labor.

Mark Pease

I think it depends on what area that we ramp up in. obviously Michigan has a little longer lead time at production on line but there are areas where we’re immediately tied in and producing as soon as the well is completed. So its kind of a mixed bag there. A lot of it depends on which commodity rebounds in which way.

Operator

Your next question comes from the line of [Michael Shulton – Ingalls and Snyder]

[Michael Shulton – Ingalls and Snyder]

Question about your hedges, as you look at your exposure and your counter party risk are you thinking that there might be moments where you take off more of these hedges particularly to keep your counter party risk down. How do you think about that.

Jim Jackson

First I’d start by saying I think we’re fairly comfortable with our counter party risk as it currently is and our largest exposure is to JPMorgan right now and given what we’ve seen on the markets and their current risk profile we feel pretty confident that that’s not a concern. Our other counter parties are Wells Fargo, Bank of Montreal, Toronto Dominion, a pretty good slew of banks given the, given where the banking community is.

Jumping to the second part of your question, there’s a lot of value built up in our hedge curve given where the current market it on the order of close to $300 million of mark-to-market value if we were to monetize all of our hedges. That is something that we can make use of if we feel its necessary. That said the reason that we set up our hedging program and our hedging strategy was to handle the situations like we’re currently in which is down cycles.

Historically as we’ve said prior to this down cycle that when we’ve looked back historically these down cycles last anywhere from 12 months to 2.5 years and that’s why our hedging program is extended out past that 2.5 year period. In this case we’re hedged out through 2012 a significant portion of our production and we’re in a very, very fortunate position given our counter parties to be extremely cash flow positive through 2012 no matter what commodity price environment you throw in front of us.

So it’s a very enviable position to be in. That said we also did not expect for the entire financial market to blow up so that does still give us concern even though we are very cash flow positive and so we will manage accordingly and why you see our capital program coming down dramatically.

[Michael Shulton – Ingalls and Snyder]

Well you’ve certainly done a great job hedging. The other question I had was about this litigation with Quicksilver, can you comment on that at all or just your view of the situation or give us any color there.

Hal Washburn

Unfortunately we can’t. We have filed some 8-Ks with some additional information on the litigation but we can’t comment further other then to say it is ongoing.

Operator

Your next question is a follow-up from the line of Jack Ripstein – Potrero Capital

Jack Ripstein – Potrero Capital

I just wanted to get back to the debt, just so I understand completely because I don’t want to come away with a different view, but it sounds like on the debt if let’s say you didn’t, the covenants were broken or something can you just walk me through where the rotor meets the road, what would actually happen with your lenders, what’s the period for cure, what happens technically if say some of these covenants aren’t met.

Jim Jackson

Let me take that in two pieces, we obviously like everybody else are monitoring kind of perspective operations and forecasting and where we are in terms of all the existing covenants, and extremely actively, we’re also in the middle of a borrowing base redetermination process, I think that comes in to play here at some level as well. And I think that fact is once we get through the borrowing base redetermination process and see what if any impact that has on us with respect to financial covenants or restricted payments tests or otherwise, we will have a period of time to work with Wells and the balance of the bank group to the extent we need to make any modifications.

And then to the extent we end up, to the extent, or in the event we ended up in violation of the covenant, the cure period under our existing facility is 30 days so.

Jack Ripstein – Potrero Capital

It sounds to me like there will be no distribution or you can’t really declare one until you get through the borrowing base, right is that a fair assessment.

Jim Jackson

Well from a calendar point of view the borrowing base redetermination process will be concluded on April 1 so its not as though it’s an open ended process. It just has to run its course and coincidentally it really starts in earnest about this time so we don’t have a lot of perfect answers for you but we’re certainly letting you know what we know.

And the next distribution declaration date I think would be scheduled for the end of April so we’ll have the borrowing base situation resolved long before the next distribution needs to be declared.

Jack Ripstein – Potrero Capital

Is it fair to say though if I was listening to the context of this call, you don’t seem overly concerned about this borrowing base calculation that’s upcoming.

Jim Jackson

I would dissuade you from thinking that and I’ll tell you why, only because we, the borrowing base is re-determined by the bank group and its done by each bank at its sole discretion. So its not as though we can force the bank group to do anything and we like everybody else are in middle of this process where despite the fact the energy market has been a good place to lend in the last 10 or 15 years and I don’t know that this is true for any specific bank we have in our group, but it is an uncertain time for I think every bank and because of that its creating uncertainty for us.

Jack Ripstein – Potrero Capital

Are they lower, below what is outstanding at the current moment, i.e. pay us back $100 million tomorrow.

Jim Jackson

They could, the bank group could re-determine the borrowing base below what’s currently borrowed, that’s true. That is a technical matter that’s a possibility. So based on what we know today that would be very surprising given the long lived nature of our assets and the strength of the hedge portfolio which really supports our borrowing base but its technically it’s a possibility I guess.

Operator

Your next question is a follow-up from the line of John Kang - RBC Capital Markets

John Kang - RBC Capital Markets

You kind of eluded to facility restrictions and Michigan, just wondering is that why you still have 11 wells shut in as of today or was that more by choice and how should we look at Michigan in terms of [inaudible] in wells just given the past history there.

Mark Pease

The 11 wells that are shut in are more tied to permitting issues. The facility restrictions, it’s a low pressure gas reservoir. A lot of the wells flow somewhere between 10 and 15 pounds flowing surface pressure and so what we’ve seen is we brought on new wells that have a little bit higher bottom hole pressure. Its increased the pressure in our gathering systems and that has tended to reduce the volume of some of the existing wells.

So we’re in the process of going through a very detailed study in key parts of that gathering system to figure out how to de bottleneck it to get those pressures down lower and when we do that we should see an increase in volumes.

Operator

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments.

Randy Breitenbach

Thanks to all of you this afternoon for your participation. On behalf of Hal, Mark, Jim, and the entire BreitBurn’s team, I thank everyone on the call today for their participation.

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