Denbury Resources, Inc. (NYSE:DNR)
Q1 2009 Earnings Call
May 5, 2009 11:00 am ET
Gareth Roberts - CEO
Phil Rykhoek - CFO
Mark Allen - CAO
Tracy Evans - SVP of Reservoir Engineering.
Nicholas Pope - Dahlman Rose & Company
Good morning, at this time I'd like to welcome everyone to the Denbury Resources first quarter 2009 earnings call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Mr. Gareth Roberts, sir, you may begin.
Thank you. Welcome, everybody, to our 2009 first quarter conference call. As usual, we will be making some forward-looking statements so you should be aware of that.
I have with me today Phil Rykhoek, our Chief Financial Officer, we have got Mark Allen, our Chief Accounting Officer; and Tracy Evans, our Senior VP of Reservoir Engineering. They're going to be doing the talking today. I have also got Bob Cornelius with us today. He has got a bit of a sore throat so he is just going to be available for questions. He assures us it's not the swine flu so that is good.
So, I'd like to turn over the meeting now to Phil to give us the results of the first quarter.
Thank you, Gareth. Just high level here, although we experienced our first quarter loss in 10 years of $18.3 million, our clean earnings were $47.6 million, $0.19 per common share, right in line with Street estimates. To arrive at these, what the Street would call clean earnings, we adjusted the net income by the non-cash fair value charge of $106.4 million on our derivative contracts, and that's $65.9 million after-tax; $77 million of that charge related to the 2009 oil contracts that we have in place, and this mark-to-market value charge reverses a portion of that $242 million that we recognized in the fourth quarter of 2008, if you recall. This is due to the expiration of one-fourth of those contracts during the first quarter and is a result of higher prices at March 31 rather than December 31.
Our first quarter 2009 production was a company record of 53,408 BOEs a day, an 11% sequential increase over fourth quarter 2008 levels. As we discussed in the press release, a portion of the increase in our total company production was a bit of an anomaly as we sold a significant inventory of natural gas liquids from the Barnett Shale area, which had been produced, but not sold in the third and fourth quarters of last year due to plant shutdowns caused by Hurricane Ike.
Our tertiary production, which we pre-announced a couple of weeks ago came in just as expected at 22,583 barrels a day, a 3% sequential increase over the fourth quarter of '08. Tracy will be giving you more details on tertiary production in a few minutes.
With that, I'll turn it over to Mark Allen to review the operating results in more detail.
Thanks, Phil. As we have typically done, I will primarily focus on the comparison of the fourth quarter of 2008 and the first quarter of 2009 rather than the comparative first quarter.
During the first quarter of 2009, our tertiary production was in line with our expectations, an increased 3% from the fourth quarter. Production from our non-tertiary properties was also in line with our expectations for the most part, increasing total production of 11% overall from Q4. This increase also included two months of production from Hastings Field, which added about 3% of this increase.
Our Barnett Shale production came in ahead of our expectations primarily due to the sale of additional natural gas liquids that we were not able to sell in the third and fourth quarters of last year due to plant shutdowns associated with Hurricane Ike. As a result of our higher than expected Barnett Shale production in the first quarter and projections for the rest of 2009, we are increasing our production forecast from 50,000 BOE per day to 51,000 BOE per day for the full year 2009, and reaffirming our projected tertiary production for 2009 of 24,500 barrels per day.
Similar to our fourth quarter, the biggest impact on our results of operations was the drop in commodity prices. Our realized oil price, excluding derivative contracts dropped 28% in the first quarter as compared to the fourth quarter and natural gas prices dropped 33%.
Our NYMEX oil price differentials, which looked particularly strong during February, reverted back to more historical levels and averaged $3.99 per barrel in the first quarter as compared to a NYMEX oil differential of $3.59 per barrel in the fourth quarter.
Going forward, we do not expect our differentials to change significantly, but may increase to more historical levels if oil prices continue to move up. Our total corporate lease operating costs decreased approximately 6% sequentially on an absolute basis and 13% on a per BOE basis from $17.90 per BOE last quarter to $15.59 per BOE this quarter.
As you might expect, this was driven primarily by lower tertiary operating costs per BOE, a 6% sequential decline between Q4 and Q1 from $21.86 during Q4 to $20.48 in Q1.
For those of you that have seen our recent analyst presentation our website, we have broken down our tertiary operating costs into major categories and whether or not we expect them to correlate with the price of oil. Our most significant tertiary costs are costs of CO2, which as expected had the biggest decrease, as it had the highest correlation with oil prices accounting for a reduction of slightly over $1 per BOE in our tertiary operating costs between Q4 and Q1.
This was primarily due to the drop in our costs of CO2 from $0.15 in Q4 to $0.14 in Q1, the increase in tertiary production and a slight reduction in the amount of CO2 we used. The other primary reduction in tertiary LOE costs per BOE was our work over costs. We have yet to see much decrease in our power costs due to the regulated environments in which we operate, but we would expect these costs to come down over time if natural gas prices remain low.
Also, we expect that our equipment rental costs may increase by up to $1 per BOE if we are successful in securing up to $100 million in operating leases for certain equipment, our goal for 2009.
Looking forward, we expect to have some additional savings in our operating costs, if commodity prices remain at current levels. You might want to review our analyst presentation for more details, but we think our tertiary operating costs should be reduced to below $20 per barrel in this commodity price environment, but will vary depending upon production response from our new tertiary floods.
G&A expenses increased from Q4 levels due primarily to employee-related costs and the recording of $2.6 million in expense for the compensation agreement we entered into with Genesis management at the end of 2008. In the fourth quarter of 2008, we adjusted our bonus accrual down to the 75% level, which lowered our G&A by a few million dollars.
For 2009, we are accruing at a higher level and we also gave salary adjustments in the first quarter of 2009. First quarter's G&A generally also trends to be slightly higher than the rest of the other quarters.
The agreement we have with Genesis Management allows them to earn up to 70% of the incentive distribution rights that we receive as being the general partner of Genesis. The value of this award may fluctuate from period to period, but for the current time we would expect the accrual for 2009 to be relatively equal each quarter and less in future years.
While we have taken some cost savings measures, such as reducing our rate of hiring, we do not plan to reduce our headcount and would expect our G&A rate including the Genesis compensation expense and franchise taxes to be in the mid to upper $4 range per BOE, similar to Q1.
Interest expense increased sequentially from $8.6 million to $12.2 million, primarily related to the February sub-debt offering and increased bank debt. Phil will discuss more about our liquidity position momentarily.
Our capitalized interest for the quarter was $12.4 million. Going forward, we expect that our capitalized interest will continue to increase in subsequent quarters up to a few million dollars as our pipeline construction costs increase. Debt will also decrease depending upon the movement of our unevaluated properties [till proven].
DD&A for oil and gas properties increased on an absolute basis, but decreased on a per BOE basis from Q4 due primarily to the full cost pool write-down we recorded at year-end.
During the first quarter, we completed the Hastings Field acquisition for a combined purchase price of approximately $248 million, including the approximate $50 million option payment. The new acquisition accounting standard, FAS 141(NYSE:R), became effective for companies at the beginning of this year. This new accounting standard, at least for this acquisition, has changed the way that we have historically recorded the allocation of purchase price between proved and unevaluated properties, which historically was to classify the acquisition costs between proved and undeveloped properties on relative value basis.
Under the new standard, we are required to consider what another market participant would pay for the property based on information available on the date of acquisition and use that data and other assumptions to determine the fair value allocation. As a result, because of our unique business model, access to relatively cheap CO2 and the decrease in prices between December 31 and the closing date, we recorded $138.7 million as goodwill related to this acquisition and nothing to undeveloped properties. This goodwill is not amortized but will be evaluated at least annually for impairment.
On the tax front, we currently do not expect a significant change in our tax rate, but we do expect to have between $5 million and $10 million of current tax expense related to state taxes throughout 2009.
With that, I will pass it back to Phil.
Thank you, Mark. Thank goodness we have Mark and his staff to help us sort out some of these new accounting pronouncements that end up with us booking goodwill.
I want to talk just a little bit about liquidity. Let me pick up from the last conference call. At that time, if you recall, we had just finished the sub-debt issuance and used the $380 million of proceeds to repay most of our bank debt. That debt issuance gave us liquidity that we needed for 2009 so since then we have been focused more on 2010 and beyond, and as such have begun to layer in additional commodity derivative contracts.
To date on the oil side, we have swaps covering 25,000 barrels a day during the first quarter of 2010 at an average price $51.85 and for the second quarter we have callers covering 25,000 barrels a day with a floor price of $50 and a ceiling price of around $75.
We have also locked in over half of our projected natural gas production with swaps for 2010 covering 55 million a day at an average price of $5.66 and swaps through 2011 covering 40 million cubic feet a day, average price of $6.21. We put this in place in order to protect our 2010 capital budget to provide a minimum level of cash flow for us next year. We picked a floor price of $50 as that was simply our pain point.
I think it is likely that we will layer in some additional oil hedges for the remainder of 2010 later this year, all part of our desire to protect our capital budget. If you notice, we have put in callers in the second quarter so we would get part of the benefit if prices increase and we will likely attempt to do that in the future as well. These hedges are with five different counterparties, all part of our 12 bank group that make up our credit line.
We do our hedging with our bank group as it effectively eliminates the possibility of a margin call as our banks are secured on the derivative contracts just as they are on our credit line. Of course, it also gives them additional business, which helps to keep our other cost of credit to a minimum.
Our 2009 capital budget remains at $750 million plus the already closed Hastings acquisition of $200 million. Included in this capital budget, of course, is almost $500 million or actually about $485 million, I guess, relating to the CO2 pipelines, the majority of which is to build the Green CO2 pipeline. This budget assumes that we fund approximately $100 million of budgeted expenditures with operating leases.
Since we don't expect to pay much in cash income taxes this year due to lower commodity prices and the fact that these have decent interest rates, plus being an alternative source of liquidity, we have resumed our equipment leasing program in 2009.
We've budgeted $100 million of leasing, although to date we have only closed on approximately $18 million and we have another $20 million to $25 million that we would expect to close around mid-year. However, use of these operating leases is dependent upon our ability to secure acceptable financing, so it is possible that we don't lease as much as we have budgeted, in which case, we would fund any shortfall with our bank credit line.
Based on our current cash flow projections and using current prices, we anticipate our '09 capital expenditures will likely exceed cash flow by $450 million to $550 million. We have already funded the majority of this shortfall with the proceeds from our sub-debt issuance and we plan to use our bank credit line for the remainder.
Today we would expect to have bank debt of $200 million to $250 million by year-end 2009 out of a credit line of $750 million, so that leaves us a minimum of $500 million of availability. If you regularly follow us you will note that this projection is not materially different than it was six months ago as the fluctuation in commodity prices has had little impact on our cash flow because of our significant '09 oil hedges.
Our bank line and borrowing base were recently reaffirmed as of April 1st, so our credit is in very good shape. They reaffirmed $1 billion borrowing base and $750 million commitment. With the $250 million cushion between the borrowing base and commitment amount, plus perhaps even a little more beyond that we do not expect this credit line to be reduced unless commodity prices were to decrease from current levels significantly.
Although we have protected part of our downside for next year, we would love to have a little more money in order to accelerate our 2010 capital program. To do so, we require some other capital source that we could possibly raise additional capital if it's possible to do so in an economic manner.
Such additional capital sources could include the sale or joint venture of assets (inaudible) leases or any other options that may become available. However, if we don't obtain additional funds, our spending program is flexible next year, and we can limit our capital spending to our available cash flow.
We have two significant things that we need to do next year. One is to finish the Green Pipeline, which is currently estimated costs around $80 million; and two, start preparing Hastings Field and spending [money] there, which requires us to spend $27 million based upon the agreement with the seller.
The remainder of our capital spending can be adjusted up or down as need be, knowing that the more we spend the faster we can grow our production.
So bottom line, we have good liquidity. We're continuing to monitor the markets, our spending and ever-changing economic environment and plan to do our best to keep this company strong.
With that, I will turn it over to Tracy who is going to review operations.
Thank you, Phil. I will give a quick update on our major projects, our enhanced oil recovery projects, operating expense efforts, and our anthropogenic CO2 efforts over the past quarter. As we previously released this morning in the press release, Denbury's first-quarter production averaged 53,408 net barrel of oil equivalents per day, which is an 11% increase over the fourth quarter of 2008. CO2 tertiary production averaged 22,583 net BOEs per day during the quarter, a 3% increase over the fourth quarter of 2008 and a 32% increase over the first quarter of 2008.
Tertiary production increases occurred in 7 of our 10 producing CO2-EOR fields on a quarter-to-quarter basis. Fields that did not show an increase were Mallalieu, where we've had some production shut in as we expand our production facilities to handle additional volumes of recycled CO2; Little Creek area, which is our most mature field; and in Martinville, which is our smallest field, which had a slight 95 net BOEs per day decrease during the quarter.
In Southwest Mississippi Phase I we have the five major field areas consisting of Little Creek, Mallalieu, Brookhaven, McComb-Smithdale, and Lockhart Crossing fields. Fields with increased production quarter-over-quarter were Brookhaven, McComb-Smithdale, and Lockhart Crossing. Brookhaven during the quarter increased production 9% from 3,178 net BOEs per day in the fourth quarter to 3,451 net barrels per day in the first quarter of 2009. The increase in production primarily came from new responding wells in our fifth development phase of the field.
We've also installed a fourth high-pressure CO2 recycle compressor and added additional fluid handling capacity at the production facility. Lockhart Crossing increased approximately 10% from 555 barrels per day during the fourth quarter to 607 barrels per day during the first quarter of 2009. McComb-Smithdale increased from 2,092 barrels per day in the fourth quarter to 2,246 barrels per day in the first quarter of 2009.
Phase II, which consists of the currently producing fields Eucutta, Soso, and Martinville, increased production quarter-over-quarter about 2% and Phase II also consists of Heidelberg Field, which has not yet begun to produce.
At Eucutta, production improved about 8% quarter over quarter with production increasing from 3,538 barrels per day to 3,813 net barrels per day during the first quarter. We enhanced the operational efficiency of the facility by adding additional compression, removing bottlenecks in the system, and adding heat capacity to assist our oil and CO2 separation. We completed the work to increase the facility's recycle capacity by approximately 100 million cubic feet per day to now a capacity of 180 million cubic feet per day.
Soso Field continues to be one of our better performing tertiary fields in terms of produced CO2, gas-to-oil ratio. Soso averaged 2,705 net barrels per day during the first quarter, which was essentially flat to the prior quarter. We continue to work with our water handling, piping, and vessel modification to increase the produced fluid and water handling capacities at Soso Field.
Heidelberg, which is our largest Phase II field in terms of reserve potential, we began first CO2 injections at Heidelberg during December. We've been working on our production and recycle facilities, which is well underway and on schedule, and we still expect first tertiary production from Heidelberg during the second half of 2009.
At Phase III Tinsley, which is our largest tertiary flood to date, production increased 30% from the fourth quarter of 2008 to the fourth quarter of 2009 with the actual production rates going from 1,832 barrels per day in the fourth quarter to 2,390 barrels per day during the first quarter of 2009. We continue the expansion of our CO2 recycling facilities, completed construction on our second production test site facility, and continued our recompletion wells in the second phase of the field expansion.
Our development plan in 2009 has not been altered and thus we expect continued success at Tinsley. Cranfield, our current Phase IV CO2 project, continues to respond although we did not book any proved reserves associated with the field during the first quarter of 2009 as production was limited to only a couple of wells. At the present time, there are 11 injection wells at Cranfield placing approximately 60 million cubic feet of CO2 per day into the reservoir.
Several of the eight planned producers that exist began producing water during the fourth quarter of last year. We saw our first initial oil production in two of the producing wells during the first quarter, which was slightly ahead of schedule. However, since production averaged only 144 barrels per day during the first quarter, most of which is from only one well, we did not recognize any proven reserves due to the limited response, and the plan is to recognize proved reserves when our production response is more widespread and substantial.
At Jackson Dome, where we get 100% of our CO2 today, we average 732 million cubic feet of CO2 per day during the first quarter, which was slightly less than the fourth quarter of 2008. The reduction is attributed to well work and our facility work at Brookhaven and Tinsley Fields, as well as Heidelberg where during the first quarter we reached our targeted reservoir pressure and actually ceased injections.
Lockhart, Cranfield, Little Creek, Martinville, and Soso fields were at or above our CO2 injection forecast during the first quarter. We continued capital projects in the Jackson Dome area to improve production performance. We're working on constructing a new dehydration facility, which we call the Trace Dehydration Facility, and several interconnecting pipelines are also being constructed as looped lines in order to connect new wells.
We now have the capability to produce and transport in excess of 900 million cubic feet per day up to approximately 1 Bcf per day. We are on target to reach our goal of having the capacity of being able to produce in excess of 1 Bcf per day of CO2 during 2009.
In Delhi, our Phase V project is continuing to progress. We completed the construction of the 78-mile Delta Pipeline from Tinsley Field to Delhi Field. Final pipeline commissioning will be completed during the next month or so, and well work has begun and will be increasing during the second quarter as we bring in a drilling rig to initiate the first phase of the drilling program.
The Delhi CO2 central facility construction is on schedule with completion expected during the fourth quarter and we should be commencing injection of CO2 into the field during the third quarter of 2009. We expect our first tertiary production response from this field in the first half of 2010.
The Green Pipeline, which is our largest project this year, we have mobilized a total of three construction crews during the first quarter. We have welded over 76 miles of pipe and completed over 24 horizontal drills along the pipeline right-of-way. Our plans are to continue the construction from Donaldsonville, Louisiana, to Oyster Bayou on the Westside of Galveston Bay and expect completion of that segment by the second quarter of 2010. Then we will complete the pipeline into the Hastings Field by the fourth quarter of 2010.
We are pleased to report that our teams continue to focus on lease operating expenses and we have made progress reducing operating costs during the first quarter. As discussed by Mark, during the quarter we reduced tertiary unit operating expenses by almost 6% from $21.86 per barrel in the fourth quarter of 2008 to $20.48 per barrel during the first quarter.
We continue to review operating expenses in an attempt to drive down operating expenses. I believe we will be able to reduce operating costs further in the coming months if commodity prices remain at these lower levels.
During the first quarter of 2009 we were successful at signing an additional four CO2 contracts with potential gasification projects. Three of these projects were in the Midwest, which of all were to be constructed with supplies, efficient CO2 supplies to justify the installation of a CO2 pipeline from the Midwest area through Tinsley Field and connect with our Delta Pipeline.
The fourth contract we signed with a potential gasification project in Mississippi. In the event this facility is constructed, a CO2 pipeline would be required to connect this potential facility with our Free State Pipeline. This new pipeline would run fairly close to Citronelle Field, our Phase-VI CO2-EOR project.
Based on the seven contracts with potential gasification sources, we have now contracted approximately 1.5 Bcf of CO2 per day if all of them were to be constructed. To date to our knowledge none of these potential sources have secured sufficient capital resources at the present time to begin actual construction. We also continue our efforts to discuss and negotiate with several existing emitters of CO2 along the Green Pipeline with the intent of acquiring CO2 from some of these sources in the near future.
At the present time we have not concluded any discussions or contracted any of these current emission sources. With that I will turn it back to Gareth.
Thanks. Now we will take questions.
(Operator Instructions) The first question comes from [Scott Billmouth].
Hey, guys. Quick question, can you give some guidance on the tertiary production ramp up throughout the year?
Well, we are keeping our average rate confirmed at 24,500 barrels per day and the actual forecast actually was relatively flat during the first part of the year with a ramp up during the third and fourth quarters. So we are probably slightly ahead of schedule, but until we see more confirmation of maintaining above schedule we just don't feel comfortable increasing our average rate at this point in time.
And the drivers of the back half of the year are obviously Heidelberg coming online and what else?
Cranfield and Heidelberg are two areas that we expect to see, relatively on a percentage basis, ramp ups in production and then also Lockhart as well, and Tinsley also. We expect it to continue to ramp up.
It is a pretty proportional increase each quarter at this point. It's not too far from being a straight line.
Your next question comes from the line of Nicholas Pope.
Nicholas Pope - Dahlman Rose & Company
When you look at pricing realizations, I guess what we are all seeing on the gas side for Barnett and what do you all think that is going to be going forward here for the rest of the year?
We have still been running $0.75 to $1 in the Barnett; it really hasn't improved too much even though prices have come down. So at this point you just have to assume it's going to stay at that level.
Nicholas Pope - Dahlman Rose & Company
All right. Just jumping around here, but looking at Mallalieu, I guess the operational issues that you all have been seeing there, do you all expect it to kind of flatten out at some point? When do you all expect to see Mallalieu kind of responding to some of the work you are all doing their on the surface side?
The issue that we have there is, obviously, we've reached recycle capacity at the facility. So at that point in time you can only handle a fixed amount of CO2 and so we have to manage that on a daily basis of bringing wells out or shutting wells in to maintain a relatively constant CO2 rate there.
What we are doing is, we are actually expanding our CO2 recycle capacity there, but that will not be completed until probably the fourth quarter of 2009, so right now we are just going to manage the field the best we can, maintaining as higher production rate as we can. Then once we get the new compressor and production facility online at that point in time we expect to see some of the production rate return.
There is quite a bit of production shut in basically, because the facility can't handle it.
Nicholas Pope - Dahlman Rose & Company
What was the Mallalieu production in the first quarter?
It was just under 4,500 barrels per day; 4,490.
Nicholas Pope - Dahlman Rose & Company
Actually what was Martinsville as well?
Martinville production during the first quarter was 1,118.
We do also have those on our analyst slideshow, if you want to look at them on the Internet too. Also just to finish, to give you the numbers it was $0.81 negative differential in the first quarter on the Barnett Shale and $0.72 last quarter.
Your next question comes from the line of [Scott Billmouth].
Sorry, guys. I got cut off there earlier. Jackson Dome production still expected to be 1 Bcf a day by midyear?
We probably have the capacity to produce that, whether or not we are actually producing that or not will depend on how fast we progress in Delhi and bringing that injection up. But we will have the capacity to do that.
Okay. And then at the Analyst Day I thought you guys were alluding to maybe a ceiling test write-down in first quarter and it looks like you guys didn't have one. Did I miss anything there?
No, we said that it was marginal and if prices remain at such low levels, it was possible and we did not record one in the first quarter but we don't have a lot of cushion.
Oil prices were basically similar.
Oil prices were slightly higher and natural gas prices were lower. Since we are more oily we got a little bit more bang for that and we ended up okay for the first quarter.
It was the benefit of having oil, predominately oil instead of natural gas.
It's close though so we are still susceptible to having one in the future.
We will accept some increases in prices, yes.
Your next question comes from the line of [Xin Liu].
A quick question on your G&A. You had a pretty high G&A number in your first quarter and if I remember correctly, in your last conference call you said G&A will be in the upper $3 per BOE. Is that number still valid or do you expect a higher number?
One thing that we did not discuss and that was not factored in that number was the Genesis compensation agreement that we had reached with management. That added $2.6 million during the first quarter, which accounts for most of the increase. And if you look back to Q4 we did have a bonus reduction in Q4 to account for the year results. Going forward we are looking at the mid to upper $4 range with the expectation that that $2.6 million of the Genesis compensation entry will be fairly consistent throughout the year.
Okay. Another question on the recording the group (inaudible), so does that mean your tax benefit will be lower because of this?
No, from a tax standpoint we anticipate the purchase price to be fully deductible. So that goodwill on our books will be deductible for tax purposes. What it really means is that when we do have potentially the tertiary reserves down the road we will not have any unevaluated properties to move into or our full cost pool. So you will get a little bit of a mismatch from that.
There are no further audio questions in queue.
All right. Well, thank you, everybody and we will talk to you next time. Thanks.
Thank you, ladies and gentlemen for your participation in today's conference call. You may now disconnect.
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