BreitBurn Energy Partners L.P. (BBEP) Q4 2009 Earnings Call March 11, 2010 1:00 PM ET
Jim Jackson – EVP and CFO
Hal Washburn – Chairman and Co-CEO
Randy Breitenbach – Co-CEO
Mark Pease – EVP and COO
Richard Roy – Citigroup
Praneeth Satish [ph] – Wells Fargo
Good day ladies and gentlemen, thank you for standing by and welcome to the BreitBurn Energy Partners investor conference call. The Partnership 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, Thursday, March 11, 2010. A replay of the call will be accessible until midnight, Thursday, March 18, by dialing 888-203-1112 and entering conference ID 9644200. International callers should dial 719-457-0820. An archive of this call will be available on the BreitBurn website at www.breitburn.com.
I would now like to turn the conference over to Jim Jackson, Chief Financial Officer of BreitBurn. Please go ahead sir.
Thank you and good morning everyone. On with me today are Hal Washburn, Randy Breitenbach, BreitBurn's Co-Chief Executive Officers; Mark Pease, BreitBurn's Chief Operating Officer; and Greg Brown, our EVP and General Counsel. After our formal remarks, we'll open the call for questions from securities analysts 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 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 about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change from those we projected over the course of the year.
A detailed discussion of many of these uncertainties is set forth in the cautionary statement relative to forward-looking information section of today’s release and under the heading ‘Risk Factors Incorporated by Reference’ from our Annual Report on Form 10-K for the year-ended December 31, 2009, which will be filed 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 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 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 and thank you for joining us today to discuss our fourth quarter and full year 2009 results. Beginning of 2009 presented us with a myriad of obstacles. Market instability, the financial crisis, a precipitous drop in commodity prices and restrictions under our credit facility which caused us to make the difficult business decision to temporarily suspend distribution.
As we stated last April, we determined that the best course of action was to spend the remainder of the year focusing on increasing our overall financial flexibility by controlling expenses, reducing our capital spending program, funding operations to adjust internally generated cash flows and dramatically lowering our outstanding borrowings.
With 2009 now behind us, the progress we’ve made to achieve these goals is clearly evident in our fourth quarter and year end 2009 results. We are extremely proud of our team for delivering results that are well advanced or as in the case of our total production level of 6.52 million barrels of oil equivalent exceeds our guidance. Our operations team really outperformed during this difficult year and exceeded all of our expectations. Mark will give you more details on there later.
Our fourth quarter adjusted EBITDA totaled $49 million and 2009 adjusted EBITDA was approximately $195 million which is at the high end of our guidance. Additionally, we ended the year with outstanding borrowings of $559 million, which represents almost a $180 million of debt pay down during the year. Certainly our yearend results exemplify the partnership’s ability to perform and delivery even in the most challenging of times. We want to thank everyone at BreitBurn for persevering under pressure and all of our investors for standing by us through such as uncertain times.
2010 has begun on a further positive note. In February, we announced that we reached an agreement with Quicksilver Resources to settle all litigation between Quicksilver and the partnership and its directors. We’re extremely pleased with the outcome, and we look forward to a productive relationship with Quicksilver that will benefit all of our limited partners.
Additionally, we announced our intention to reinstate distribution at an annual rate of $1.50 per unit or $37.50 quarterly beginning with the first quarter of 2010 payable on or before May 15 of 2010. We are ready now return to our core strategic goals. With our increased financial flexibility and the improvement of commodity prices in overall market conditions, we’ll be ramping up our capital spending program in 2010 and our new capital budget target to be between $72 million and $78 million compared to the $28.7 million we spent in 2009.
As a result of our increased capital spending we expect production to be approximately $6.3 million to $6.7 million barrels of oil equivalent in 2010, which is an increase over 2009 guidance. We will continue to emphasize consistent cash flow generation to support distributions to our unitholders, work to maintain a slightly growth production with our expanded 2010 capital program and actively evaluate acquisition opportunities in line with our growth through acquisition strategy while always maintaining our financial flexibility and liquidity.
With that, I will turn the call over to Randy who will briefly cover some selected results for the quarter and the year and discuss our hedging activity. Randy?
Thank you, Hal, and welcome everyone. I will cover details of our commodity hedging activity and the impact of these derivative instruments on our fourth quarter and full year results. For the fourth quarter of 2009, crude oil and natural gas sales totaled 92.5 million, up 6% from 87 million in the third quarter, primarily due to recovering commodity prices. 17.8 million of the sales total were a result of realized gains on commodity derivative instruments for the period.
For the full year 2009, crude oil and natural gas sales were 422.6 million, of which 167.7 million were a result of realized gains on our hedges. The significant gains from commodity derivative instruments demonstrate the value of our hedge portfolio during periods of depressed commodity prices.
The value of our robust hedge portfolio can also be exemplified by comparing the actual NYMEX price for the period with the effective price we received for the same period including the effects of our hedges. Our realized natural gas price for the fourth quarter averaged $7.55 per Mcf compared with the NYMEX natural gas price of $4.93 per Mcf, and average realized crude oil and liquids prices were $69.72 per barrel, slightly lower than the NYMEX crude oil price of approximately $76 per barrel for the same period.
For the full year 2009, realized natural gas prices averaged $7.48 per Mcf as compared to a full year NYMEX natural gas price of $4.16 per Mcf, and for crude oil our full year 2009 realized crude oil price of $66.27 per barrel as compared to approximately $62 per barrel, reflecting increases in commodity prices non-cash unrealized losses from commodity derivative instruments for the fourth quarter were $54.7 million. For full year 2009, non-cash unrealized losses from commodity derivative instruments were $219.1 million. Consistent with our strategy to mitigate commodity price volatility, we continue to opportunistically layer in new hedges.
As we mentioned in our third quarter call, we put hedges in place in October, which cover approximately 456,000 barrels in 2013 and 2014 at an average price of $83.99 per barrel. So far in 2010 we have hedged an additional 1.278 million barrels, which cover oil production from 2011 through 2013 at an average price of $85.39 per barrel.
An updated presentation of the Partnership's commodity price protection portfolio as of March 11, 2010 will be made available in the Events & Presentations section of the Investor Relations tab on our website. Assuming the midpoint of 2010 production guidance is held flat, our production is hedged at 84% in 2010, 79% in 2011, 70% in 2012, and 56% in 2013. Average annual prices during this period range from $78.64 and $87.88 per barrel for oil, and $6.92 and $8.26 per MMBtu for gas.
As we move into 2010, our hedged portfolio will continue to play an integral role in our overall business strategy. It has proven successful in mitigating commodity price volatility, stabilizing revenues and cash flows and supporting our borrowing base during the market instability we faced over the last year and half. We are in a strong position looking into the future because a significant portion of our oil and gas volumes are well protected at very attractive prices through the next five years. We will continue to evaluate our hedging portfolio as we grow, and add new production and plan to hedge accordingly.
With that, I will turn the call over to Mark Pease who will provide you with additional details of our operating performance. Mark?
Thanks, Randy. As Hal mentioned, operationally we had an excellent year in 2009. In the fourth quarter, we produced 1.632 million barrels equivalent of oil and gas which is just about flat to the prior quarter’s production of 1.628 million barrels equivalent.
Full year production came in at 6.52 million barrels equivalent or 17,900 barrels per day which is just above the high end of our guidance range and a decline of about 4% compared to 2008. We are pleased with our production performance considering the capital expenditures in 2009, where only $28.7 million and $10.9 million of that was spent in the fourth quarter which did not add significantly to production for the full year.
Overall production split for the year was approximately 54% natural gas and 46% crude oil and NGLs. Lease operating expenses and processing fees, excluding transportation expenses came in at $31.7 million or $19.31 per Boe for the fourth quarter of 2009, and a $118.4 million or $17.90 per Boe for the full year, which is within our guidance range. Our operating team has done an excellent job working with our service and materials providers the lower cost during 2009.
However, as we said in the past, costs were strongly influenced by the price of oil and natural gas and while we did see reductions in cost in the first half of the year, some costs bottomed out during mid 2009 and then increased in the last few months of the year as oil prices rose. This impacted fourth quarter lease operating expenses particularly in our western division -- productions primarily oil.
Total capital expenditures in the fourth quarter were $10.9 million with full year expenditures of $28.7 million. Given our 2009 production performance and the thorough evaluation of our portfolio of opportunities going forward, we have adjusted our 2010 guidance from maintenance capital downward to a range of $40 million to $50 million. We plan to spend above that amount during 2010 with a guidance midpoint of approximately 75 million, which should enable us to grow production slightly.
Let me update you quickly on our reserves before getting into more detailed operational results. As of December 31, 2009, our total estimated proved oil and gas reserves were 111.3 million barrels equivalent which compares to year end 2008 reserves of 103.6 million barrels equivalent. The year end 2009 reserves are split about 65% natural gas and 35% crude oil and 91% of those were classified as proved developed reserves. Standardized measure of net future cash flows from the production of these reserves discounted at 10% is approximately $760 million using prices and costs in effect as of the date such estimates were made, and which are held constant throughout the life of the properties.
Of the total estimated proved reserves, 68% were located in Michigan, 14% in California, 10% in Wyoming, 7% in Florida with the remaining 1% in Indiana and Kentucky. During 2009, the Partnership had proved reserve increases totaling 7 million barrels equivalent due to drilling, rig completion and workovers, which equates to 108% of the Partnership’s production for the year. The remainder of the increase in reserves from prior year was primarily due to increases of $9.8 million barrels due to economic factors, such as higher prices offset by 1.5 million barrels of negative technical revisions, 6.5 million barrels of 2009 production, and 1.1 million barrels of reductions due to the sale of Lazy JL Field in Texas.
Reserves as of December 31, 2009 were determined using an average WTI price, $61.18 per barrel and average Henry Hub price of $3.87 per Mcf. Those compared to yearend 2008 prices of $44.60 per barrel for WTI and $5.71 per Mcf.
Moving on to fourth quarter performance in our two operating divisions, both divisions performed well. With the Eastern division exceeding their goal during the quarter, which continues the trend they set in the first three quarters of 2009. Production in Eastern division increased slightly in the fourth quarter, which is a result of several successful capital projects completed during the period, offset by normal production declines. Eastern production for the year was about 5% higher than target due to the results from our capital program that exceeded forecast and better well surveillance.
Further in the Eastern division, capital activity in the fourth quarter consisted of one rig completion, five well workovers, and five facility optimization projects, which were four line twining projects and one compression project. In Michigan during full year of 2009, capital was spent to complete a total of 19 rig completions or workovers and 12 line twining projects and compression optimization projects.
In the Western division, we completed six productive development wells in Wyoming and four in California during the year. Before California wells were drilled and completed during the fourth quarter and had an initial production rate of about $460 barrels per day, almost double the expected 235 barrels a day. In the same period in Wyoming, two injection wells were drilled and completed.
Let me conclude with a few notes on operating guidance. In 2010, we will be operating under a significantly increased capital spending program, and are expecting a production range of $6.3 million to $6.7 million barrels equivalent. We anticipate spending approximately 60% of those dollars in our Western division, where production is essentially all oil, and approximately 40% of the dollars in our Eastern division where production is mainly natural gas. We plan to drill or re-drill approximately 40 wells with about 60% of our total capital spending focused on drilling, 20% on mandatory projects, and 20% on optimization projects. Of the 40 wells to drill or re-drill, 19 are expected to be in Michigan, 14 in Wyoming, four in California, two in Florida and one in Kentucky.
Now let me explain the little bit more about our 2010 capital program and its forecasted results. Due to the timing of some of our key projects and winter weather constraints in Wyoming and Michigan, we only execute about 10% of our program during the first quarter. This concentration of activity in the second and third quarters enables us to much better control costs, but does not provide the same production volumes as if the work program was more evenly spread throughout the year. A better measure of the impact of the program is to compare the expected production exit rate of 2010 to the 2009 exit production rate. The program more than offsets our natural decline and should deliver mid-single digit growth over the course of the year.
And of course, we will continue to focus rigorously on controlling operating expenses and given the flexibility of our balanced asset portfolio we will continue to evaluate project economics for oil and gas operations as commodity prices change during the year.
With that, I’ll turn the call over to Jim.
Thank you, Mark. Let me start by reviewing some more specific results for the quarter and the year and conclude with commentary on 2010 guidance. As Randy mentioned earlier, revenue including realized gains and losses on commodity derivatives instruments increased 6% in the fourth quarter to $92.5 million from $87 million in the third quarter, primarily due to improved oil and gas price environment.
General and administrative expenses excluding unit based compensation expense were $6.2 million in the fourth quarter versus $5.8 million in the third quarter. On a full year basis, G&A totaled $23.7 million compared to $24.6 million in 2008, representing a 4% decrease which is reflective of our cost control efforts in this area.
Full year G&A per BOE was approximately $3.64. Fourth quarter adjusted EBITDA was $49 million, up from $48.4 million in the third quarter. Full year adjusted EBITDA was approximately $195 million, which again, is at the high end of our 2009 guidance range. Production and property taxes totaled $6.1 million in the fourth quarter as compared to $4.4 million in the third quarter. The increase in taxes was principally due to higher natural gas and oil prices.
Net interest and other financing costs excluding realized and unrealized gains and losses on interest rate swaps for the fourth quarter were $4.1 million compared to $4.5 million in the third quarter; including realized losses of approximately $3.4 million on interest rates swaps, cash interest expense, totaled $6.8 million in the fourth quarter of 2009. Full year cash interest expense totaled $28.4 million which is well below our 2009 guidance range of $32 million to $34 million reflecting the success of our debt reduction efforts throughout the year.
We recorded a net loss of $39.7 million or $0.75 per limited partnership unit for the fourth quarter and a net loss of $107.2 million or $2.03 per unit for the full year 2009. Losses were primarily due to significant unrealized losses on commodity derivative instruments of $54.7 million in the fourth quarter and $219.1 million for the full year. Let me now turn to our much improved liquidity position. We reduced outstanding borrowing by $26 million in the fourth quarter from $585 million at September 30 to $559 million at year end, which is slightly less than prior quarter’s that was expected given the ramp up in the first quarter.
During 2008, we have reduced outstanding borrowings by approximately $177 million. As of February 28, our outstanding debt was $550 million, which represents approximate debt reduction of $3.50 per unit since the beginning of 2009.
Now I’d like to provide 2010 guidance. As previously discussed, we significantly decreased capital spending in 2009 to conserve capital and then response to the significant decline in oil and natural gas prices at the end of 2008. Since then we’ve seen gradual increases in commodity prices and will be increasing our capital program for 2010.
We are projecting total capital expenditures for the year to be between $72 million and $78 million. These estimates include maintenance and obligatory capital expenditures as well as growth capital expenditures. Maintenance and obligatory capital are generally defined as the estimated amount of investment in capital projects, existing facilities and operation needed to hold production approximately constant from period to period.
For 2010, our guidance for maintenance capital is $40 million to $50 million. As you know, our calculation for total distributable cash flow is adjusted EBITDA minus cash interest expense, minus this maintenance capital expense. Given the ramp-up in capital spending, we’re expecting our 2010 production to be between $6.3 million barrels of oil equivalent and $6.7 million barrels of oil equivalent, with production ramping up throughout the year consistent with the timing of our capital program.
We project our production mix to be 47% oil and 53% gas for the year. Average price differentials are expected to be between 87% and 89% for oil, and between 100% and 102% for gas. With recovering commodity prices coming crisscross, therefore our expectations for operating cost in 2010 are between $19.35 and $21.85 per BOE. These estimated operating costs include lease operating expenses, processing fees and transportation expense.
Expected transportation expense totals approximately $6.7 million in 2010, largely attributable to our Florida production. Excluding transportation expense, our estimated operating cost range for BOE is approximately $18.32 to $20.82. When estimating operating cost for 2010, we are assuming flat $70 oil and $5 gas price levels in stark contrast to the flat $40 oil and $4 gas price levels we used in 2009.
Production taxes are expected to range between 7% and 7.5% of oil and gas revenues. This increase compared to 2009 reflects higher expectations for commodity prices and their impact on property value. Management expects general and administrative expenses, excluding unit-based compensation in 2010 to be between $25 million and $27 million, representing a slight increase over 2009 guidance, and consistent with a substantial increase in our 2010 activity level.
The Partnership expects to generate adjusted EBITDA, a non-GAAP measure of between $190 million and $200 million in 2010. These expectations are based on the number of operating and other assumptions, including commodity prices remaining at or near $70 per barrel for WTI crude oil and $5 per Mcfe for natural gas, like the substantial benefits of the partnership the existing hedged portfolio.
We are forecasting a cash interest expense range of $30 million to $32 million on our outstanding borrowings all of which are currently funded by a bank credit facility. This assumes a one-month LIBOR rate of approximately 2% and includes the impact of interest rate swaps covering approximately $400,000 million of borrowing at a weighted average swap rate of 3.17%.
Our resulting estimated 2009 weighted average LIBOR rate is 2.84%. Please see our detailed guidance released today for additional assumptions and a discussion of the build-up to adjusted EBITDA from estimated net income.
In conclusion, I would like to reiterate that 2009 was an excellent year operationally and that as a result of our successful efforts to improve liquidity we are in a much stronger position from a financial flexibility perspective as well. We look forward to paying off our first quarter distribution of $37.50 to unitholders in the second quarter and to a promising 2010 year for the partnership and our investors. This concludes our formal remarks.
Operator, you may now open the call for questions.
(Operator Instructions) We will take our first question from Richard Roy of Citi.
Richard Roy – Citigroup
Good afternoon. Thanks for taking my question. I might have missed this, but as you reach to the $13 million settlement cost, could you provide us an update as to if you expect to get that refunded [ph] and also is that number included in terms of your performance to your guidance?
Richard, we actually do expect that to be covered by our insurance carrier, so at this point we haven’t incorporated that into our guidance, but our discussions are ongoing and we do expect that to happen.
Richard Roy – Citigroup
Great. In term of the reserves, in your prepared remarks you discussed the increase due to economic factors price was mentioned, is it solely price or are there other factors that led to the increase? Could you provide more color, then that will be helpful.
Yes, Richard, this is Mark Pease. The majority of that is price, the rest of it is, we look at what our operating cost is each year, which affects the economic climate, so you expect coming at two different directions, the price you receive for commodity and operating cost to produce it but the majority of it is price.
Richard Roy – Citigroup
Great, great. Then last question as it relates to the acquisition market, what are you seeing there in terms of deal flow and do you have a preference for crude oil or natural gas property?
Well, Richard, we are starting to see more deal flow, and we are opportunistically looking to things at our core competencies. We are pretty well balanced between oil and natural gas, and that is an advantage that we have versus our peers. We would look at natural gas opportunities and we’ll continue to look in natural gas opportunities given the lower prices. But basically what we are looking for is acquisitions that largely fit our strategic model which is consistent, strong cash flow, the ability to maintain production flat, so long life reserves generate a lot of cash so we can use this support distribution.
Richard Roy – Citigroup
Great. Thanks very much.
(Operator Instructions) And from Wells Fargo, Praneeth Satish [ph].
Praneeth Satish – Wells Fargo
Hi, good afternoon. Have you received any indication from your lenders as to whether the current borrowing base is going to be maintained in April?
This is Jim Jackson. Our bank facility goes current at the end of 2010. We are going to, I think work to, we do that deal sooner rather than later. We have just delivered to our current lead agent all the materials that they’ll need for borrowing base redetermination. We don’t have a direct indications from them, I think what we’re hearing anecdotally from others is that, is that there hasn’t been enough net movement, if you will, for a company with balanced assets in both oil and gas to give us a sense that there is any market decrease coming or one that we’re not prepared for given the way the balance sheet looks now.
Praneeth Satish – Wells Fargo
Okay, and then the other question was the $6.7 million transportation cost, transportation expense, is that going to spread throughout the quarters or is that going to be primarily expense in one or two quarters?
The transportation expense will be incurred when we in Florida actually ship and sell product and that happens – that does not happen on a regular schedule. So that will be consistent when we actually have shipments and receive payments. That should not be spread evenly throughout the year.
Praneeth Satish – Wells Fargo
Okay. Thank you.
(Operator Instructions) There are no further questions, Mr. Washburn. I’ll turn the conference back over to you for any closing remarks.
Thank you very much, operator. On behalf of Randy, Mark, Jim, Greg and the entire BreitBurn team, I thank everyone on the call today for their participation. Operator, you may now bring this call to a close.
And this does conclude today's conference call. Thank you everyone for joining us. You may now disconnect.
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