Nov 6, 2015
Executives
Drew Mair - Manager, IR Ian Dundas - President & CEO Jodi Jensen Labrie - SVP & CFO Eric Le Dain - SVP, Corporate Development Commercial
Analysts
Greg Pardy - RBC Capital Markets Patrick Bryden - Scotiabank Patrick O'Rourke - AltaCorp Capital Kyle Preston - National Bank Jason Frew - Credit Suisse
Operator
Good morning, my name is Rob and I will be your conference operator today. At this time I would like to welcome everyone to the Enerplus Corporation Third Quarter Results Conference Call.
[Operator Instructions]. Drew Mair, Manager of Investor Relations, you may begin your conference.
Drew Mair
Thank you, Operator and good morning, everyone. Thank you for joining the call.
Ian Dundas, our President and Chief Executive Officer, will be providing an overview of our third quarter results and 2016 guidance released this morning. Jodi Jensen Labrie, Senior Vice President and Chief Financial Officer, will be giving details on our financial performance and Eric LeDain, Senior Vice President of Corporate Development Commercial, will be giving some color on our marketing and hedging activities.
Our financials have been prepared in accordance with the United States Generally Accepted Accounting Principles. All discussion of production volumes today are on a gross Company working interest basis and all financial figures are in Canadian dollars unless otherwise specified.
Conversions of natural gas to barrels of oil equivalent are done to a 6 to 1 energy equivalent conversion ratio which does not represent the current value equivalent. The information we're discussing today contains forward-looking information.
We ask listeners to please review our advisory on forward-looking information to better understand the risks and limitations of this type of information. This advisory can be found at the end of our news release issued this morning and included within our MD&A and financial statements filed on SEDAR and EDGAR and available on our website at enerplus.com.
Following our discussion we will open up the phone lines and answer questions you may have and we will also have a replay of this call available later today on our website. With that, I'll turn the call to Ian.
Ian Dundas
Thanks, Drew. Good morning everyone.
Thanks for joining us today. I'll start by running through the quarter and later we'll take you through our outlook for 2016.
We delivered yet another quarter of strong operating performance. We delivered record production on a disciplined capital program.
We're driving efficiencies across the organization and we're making progress on our non-core divestment program. The strength of our production was underpinned by our North Dakota operations which continue to achieve exceptional results.
As we continue to direct the majority of our capital to our crude oil plays we saw a meaningful increase in our oil and liquids production which averaged approximately 50,000 barrels equivalent per day in the quarter. Strength in our oil volumes has been a key driver to increase our 2015 annual production guidance to 106,000 BOE per day, with oil and liquids of 46,000 BOE per day.
Oil volumes were obviously impressive in the quarter. We saw the stars align a bit operationally during the quarter on the oil side.
The oil growth was a result of a number of factors. We had a large number of on-streams late in Q2 and into Q3 on both operated and nonoperated leases.
We also saw a significant well outperformance in what had been an average area -- at least average on our acreage -- and I will discuss that a little bit later on. As a result, we expect Q3 oil production will represent the high-water mark for our oil production for a while.
The combination of reduced on-streams in Q4, working through some flush production and the impact of oil divestments, will result in lower oil production in Q4 which obviously ties to our overall 2015 production guidance of 46,000 BOE a day of oil and liquids. Despite the expected decline into Q4 we expect relatively flat oil and liquids volumes from 2015 through 2016 even with the oil divestments that we're working on this quarter.
On the cost side, we're seeing improved performance across the Business. We now expect to spend less capital in 2015 and have lowered our guidance to CAD510 million.
This lower spend is both the result of better cost performance and strong well performance which has allowed us to defer some activity into 2016 and still achieve our 2015 objectives. We're also reducing both our operating and G&A cost guidance based upon continued cost reduction efforts and higher volumes.
We continue to have success on our non-core divestment activity. Following the quarter we signed an agreement to sell a portion of our non-operated North Dakota properties for CAD80 million.
This accretive transaction represents less than 2% of our entire North Dakota acreage position. There was also some very early stage production associated with these assets which largely came onstream during the third quarter.
We estimate that production from existing wells from this asset would be approximately 1,000 BOE per day in 2016. Including this transaction, the total proceeds from our divestments year-to-date is approximately CAD280 million from between 3,000 and 3,500 BOE per day of production depending on the measurement period.
Moving onto the dividend, we have reduced our monthly dividend to CAD0.03 per share from CAD0.05 per share, effective with the December dividend payment. This decision is based upon our strategy of having a sustainable dividend policy and ensuring we maintain our financial strength during this period of low commodity prices.
I'll now turn the call over to our CFO, Jodi.
Jodi Jensen Labrie
Thanks, Ian. Our cost reduction efforts continue to yield tangible results.
We have decreased our annual operating and G&A cost guidance for a second time this year by a combined CAD0.30 per BOE. From our initial 2015 guidance, operating and G&A costs are now expected to be down a combined CAD0.95 per BOE in 2015.
Operating costs averaged CAD8.87 per BOE in the quarter, below our guidance of CAD9.25 per BOE. As expected, we saw an increase in overall costs from the second quarter as a result of seasonal turnaround activity.
However, based on the cost reductions we have achieved to date and increased production, our revised 2015 operating cost guidance is CAD9.00 per BOE. We continue to see meaningful improvement in our cash G&A costs.
During the third quarter, cash G&A costs averaged CAD2.24 per BOE which included one-time severance charges relating to staffing reduction. Notwithstanding, CAD8.5 million in one-time severance charges year to date, we have lowered our 2015 G&A guidance to CAD2.20 per BOE.
Through the course of the year we have reduced our staff by approximately 20% as a result of lower capital spending, divestments and a concerted effort to drive efficiencies across the organization. However, going into 2016 is when we really start to see the benefits of our 2015 cost savings initiatives and reduced staffing levels.
We expect cash G&A expenses to be down approximately CAD15 million year-over-year or 20% on a BOE basis to CAD1.90 per BOE in 2016. Turning to funds flow, funds flow decreased to CAD121 million in the third quarter compared to CAD160 million in the second quarter of 2015.
The reduction is primarily due to lower crude oil prices and one-time severance charges during the period, offset by a CAD16 million current tax recovery for cash taxes we expect to recoup as a result of tax losses in the United States this year. We incurred an asset impairment charge in the quarter of CAD321 million before tax.
Unlike IFRS accounting, U.S. GAAP stipulates that we use historical, trailing 12-month commodity prices when calculating impairments.
The decline in prices over the last four quarters has continued to result in impairments each quarter. We expect the 12 months trailing price to decline further in Q4 which may lead to additional impairment.
It's important to note that this impairment reduces our earnings, but it does not impact our funds flow. In addition, because we report using U.S.
GAAP, these impairments are not reversed in future periods when commodity prices recover. Our hedging program helped support funds flow in the third quarter with a gain of CAD54 million and we expect a similar hedging gain during the fourth quarter of 2015.
In 2016 we have approximately one-third of our crude oil volume hedged, with floor protection at approximately $64 per barrel. At September 30, 2015, we were approximately 11% drawn on our CAD1 billion unsecured covenant-based bank credit facility.
Subsequent to the quarter we completed a one-year extension of our bank facility which now matures October 31, 2018. Having first confirmed with all of our syndicate banks that we could maintain the facility at its current CAD1 billion level, we chose to decrease the facility to CAD800 million.
With approximately CAD1.1 billion in term debt and no further principal repayments due until mid-2017, we do not require a large bank credit facility that would remain essentially undrawn. We believe an CAD800 million facility provides more than enough liquidity to execute our business plan which is focused on sustainability in a low commodity price environment.
In addition, we expect to realize savings of approximately CAD1 million as a result of the decreased facility size. We anticipate we will be repaying debt during the fourth quarter of 2015 and by year-end estimate being approximately 10% drawn on our CAD800 million facility.
Earlier Ian mentioned the reduction to our monthly dividend to CAD0.03 per share effective with the December dividend payment. This equates to an annual dividend level of approximately CAD74 million, a reduction of CAD50 million from the current level.
We feel that this is a more appropriate level in the context of prevailing low commodity prices. Overall we remain in a strong financial position.
We ended the quarter with a debt-to-trailing 12-month funds flow ratio of two times and a debt-to-EBITDA ratio of 1.8 times which is the most sensitive ratio in our lending agreement. I'll now turn the call over to Eric.
Eric Le Dain\
Thanks, Jodi. I'll talk briefly about our North Dakota and Marcellus differentials and where we see those going in 2016.
Starting in North Dakota, we saw improvement in our U.S. Bakken crude oil differential during the third quarter as U.S.
oil production, particularly in North Dakota, has a minimum flattened and in some months has begun to decline. Our realized Bakken differential was $8.52 per barrel below WTI, compared to $9.37 per barrel in the second quarter.
Subsequent to the third quarter we've seen differentials improve further and in 2016 we expect the Bakken differential of $8 per barrel below WTI which is for a combination of sales into pipeline and rail. Turning to the Marcellus, strong production levels and significant maintenance activities on the two major pipelines running through northeast Pennsylvania contributed to additional weakness in regional Marcellus pricing during the quarter.
Our realized Marcellus gas price in the quarter averaged $1.64 per Mcf below NYMEX. This was 18% lower than the second quarter.
In our view this could be the bottom. Reduced industry spend levels and new pipeline capacity coming on in Q4 2015 should begin to improve northeast Pennsylvania pricing from the Q3 level.
The same dynamics of industry intentions to reduce spend, along with additional takeaway coming on-stream in 2016, will further reduce the inventory of curtailed production and uncompleted wells. Basis differentials have improved subsequent to the quarter and in the region, with spot differentials in the Marcellus trading approximately $1 per Mcf to $1.50 per Mcf below NYMEX due to weaker NYMEX prices and the recent tie-in of the Columbia East project.
For 2016 we're forecasting Marcellus differential of $1.25 per Mcf below NYMEX. Turning to hedging, for the fourth quarter of 2015 we have an average of 14,500 barrels per day of crude oil, roughly 45% of our expected crude oil production net of royalties, hedged at an average floor price of $79.47 per barrel through a combination of swaps and three-way collars.
In 2016, as Jodi mentioned, we have an average of 11,000 barrels per day of crude oil, approximately 34% of our expected crude oil production net of royalties, hedged at an average floor price of $64.35 per barrel through a combination of swaps and three-way collars structures. Under our gas hedging program, for the fourth quarter of 2015 we're swapped on about 102,000 Mcf per day against NYMEX, approximately 36% of our forecasted natural gas production net of royalties and an average price just below $4 per Mcf.
In 2016 we have 25,000 Mcf per day, approximately 9% of our forecasted natural gas production net of royalties, hedged through three-way collars with an average floor price of $3 per Mcf. Now back to Ian.
Ian Dundas
Thanks Eric. Ray Daniels, our Senior Vice President of Operations, isn't here today, so I will cover Ray's portion of the call and discuss our operational performance in the quarter and then move on to 2016.
Operationally we had another safe and solid quarter with some strong well results. We had another increase in production quarter over quarter, primarily driven by North Dakota, where production averaged 32,600 BOE per day, up over 20% from the previous quarter.
We've been consistently delivering top quartile well results in Fort Berthold which is really driving our growth. Production exceeded our estimates in the quarter through a combination of strong well results in the southeastern portion of our acreage block and higher levels of activity in our non-operated North Dakota properties.
During the second and third quarters combined we brought about 16 net wells onstream both operated and nonoperated which has resulted in quite significant crude oil growth over the period. As I said earlier, we will see production volumes come down in fourth quarter.
Overall, we expect to average 46,000 BOE a day of oil liquids this year which is at the high end of our previous guidance for liquids. We drilled 3.8 net wells in Fort Berthold, with 6.5 net wells brought onstream during the quarter, for a total capital outlay of CAD58 million.
Staying with North Dakota, our well results continued to highlight the quality of our acreage position. While there remains some degree of variability across the acreage block, we're proving that performance is still top quartile even in areas which might've been considered less productive relative to our lands in the northwest portion of Fort Berthold, where our wells are among the best in the state.
All of our operated on-stream wells in the quarter were located in the southeastern area of Fort Berthold and had an average initial 30-day production rate of over 1,600 BOE per day, meaningfully outperforming our previous expectations for this specific area. Our all-in drill, complete and tie-in costs, including facilities, continued to trend down in the quarter, averaging just under CAD10 million.
We've seen a meaningful reduction in well costs year to date and, although it's challenging to accurately predict where they might go from here. We will continue to run with one rig in North Dakota and expect to drill approximately two net new wells and bring approximately four net wells onstream in the fourth quarter.
Turning to the Marcellus, there was a continued low level of spending in the quarter at only CAD3 million. Despite the low capital investment, strong well performance led to a 5% production increase to 210 million cubic feet of gas per day, higher than the previous quarter.
Our outlook in terms of activity in the Marcellus is one of continued low levels of spending until regional gas pricing improves. Moving on to the Canadian oil portfolio, following the commercial success of the polymer pilot project at our Medicine Hat Glauc C unit, we have moved forward with the installation of a second skid for our next polymer project.
Construction of the project was completed in October on budget and on schedule. Polymer injection into 12 injector wells commenced in late October.
Following this project we have two additional polymer projects lined up. Overall, our assets continue to perform at or better than our expectations which is underpinning the strength of our business.
Looking ahead into 2016 our focus is on sustainability. This has influenced our spending decisions and drove our decision to reduce our dividend.
This morning we provided 2016 guidance that will see us spending significantly less capital than 2015 while keeping production broadly flat despite the impact of today's announced divestments. We're budgeting capital spending of CAD350 million which is down 30% from 2015 levels, with production of between 100,000 BOE and 105,000 BOE per day.
Oil and liquids volumes will also be relatively flat at between 44,000 and 47,000 BOE per day. 90% of our spending will be directed to our crude oil properties as we continue to drive net back improvement.
We have based our budget on CAD50.00 TI and CAD3.00 NYMEX gas. At CAD50.00 per barrel in West Texas, our fourth quarter divestment proceeds more than fully fund any residual gap and we expect to keep debt level flat by year-end 2016.
We're also maintaining flexibility to adjust our capital budget. If we see strength in commodity prices we could potentially increase spending towards the back half of the year.
We also have some flexibility to reduce spending levels if commodity prices erode further. Our operating costs are expected to average CAD9.20 per BOE.
This is a slight increase from 2015 which is primarily due to the impact of a weak Canadian dollar on our U.S. dollar-denominated operating costs.
As Jodi discussed earlier we're starting to realize the benefit of our restructuring efforts and expect cash G&A of CAD1.90 per BOE, about 20% lower than 2015's original guidance. In summary, we will be living within our means in 2016, keeping production largely flat and not building debt levels.
Our business remains well-positioned as we plan for continued period of challenging commodity prices and, importantly, improved efficiencies across our organization mean that we're in a strong position to take advantage of opportunities and improvement in the market. With that I would turn the call over to the operator and we will open it up for your questions.
Operator
[Operator Instructions]. Your first question comes from the line of Greg Pardy from RBC Capital Markets.
Your line is open.
Greg Pardy
Ian, three questions for you. The first one is one I typically ask, but I know you provided an estimate of drilled but uncompleted wells for the Bakken as of the end of the year, but where would the tally have stood as of September 30 or is that even relevant?
Ian Dundas
It's not relevant, Greg. I'm not going to answer that question, sorry.
I think it was 11 at the end of September. When we look at the end of this year, that would be around 10.
Greg Pardy
You mentioned with respect to your capital flexibility, can you give us rough orders of magnitude then? Obviously an upside is probably harder to calibrate, but if you had to go to a bare-bones budget, is that CAD250 million, CAD275 million?
Where could that number potentially go if you needed to? Can you give us and idea of what your first quarter spending is going to look like?
Ian Dundas
We're 65% in the first half of the year. A bit more than half of that in the first quarter.
If we were to go bare-bones, I think CAD50 million reduction, something along those lines.
Greg Pardy
Okay.
Ian Dundas
It is getting closer to bare-bones at these levels.
Greg Pardy
The last one for me, at your pricing scenario in 2016 would you expect to pay any cash taxes or are those numbers potential recoveries?
Ian Dundas
I think minimal cash taxes for next year at these pricing assumptions and spending levels.
Operator
Your next question comes from the line of Patrick Bryden from Scotiabank. Your line is open.
Patrick Bryden
I've got a bit of a different question. None of us have a time machine but if we were to go back and think about the pacing of the deferred uncompleted wells, how do you think about that given what's transpired in commodity prices?
We've seen very impressive response from the asset and production peaking up here and then we have production potentially settling a little bit down into 2016. So is the pacing something you would have re-thought given where oil prices went or are you content with how the wells have been brought on in terms of completion phasing?
Ian Dundas
If you think about what was going on nine months ago we hadn't seen cost improvement and we're sitting on that low CAD40 oil deck. We didn't have all the hedging we wanted.
So then oil popped up, we were able to put hedges on at a higher -- at a level that we were comfortable with, over CAD60 and we had visibility to cost improvement which was really helping our economics. Out of that, we made a pretty modest increase in our spending.
You've got to remember at that point we had holes in the ground, we had stranded capital and so we made a modest increase. Maybe to frame the whole program for you, we would've been thinking on-streams of 15 to 20 originally.
We're now going to be just over 20, maybe 23, as we move through the year. We're doing that for about the same amount of money we said we were going to do.
So I feel pretty good about it. I don't know if you noticed but we also talked a little bit about another deferral, so we've actually taken some of the 2015 on-streams that we would have planned for as recently as two or three months ago and slid those into 2016.
I think you are seeing ground zero of the flexibility of top quartile shale plays and our ability to manage those spending levels in the context of a pretty volatile price environment.
Patrick Bryden
When we look at the uncompleted wells that were deferred and then have been executed, how do you think about those returns, given what is transpiring in the forward market here?
Ian Dundas
We have a series of type curves depending on the areas we're in. It looks like everything we have done in the last year is trending towards the high end of our type curves.
If you use those numbers, CAD50 flat oil gives us a rate of return of that call it 25% level on a CAD10 million well cost. Right now we're trending under that CAD10 million well cost and the forward curve, obviously, isn't flat at CAD50, so I feel pretty good about the economics.
They are not as exciting as they are in a CAD60 world and so we don't feel the need to go gangbusters on this, but they are acceptable and we seem to be outperforming to the upside on that.
Patrick Bryden
And just last one for me. Any elaboration on Bakken completion in terms of proppant or fluids or tonnage?
Ian Dundas
We talked a little bit about this last time. Like you are seeing in a lot of plays, there are subtleties of design that are really influencing performance, really, really depends where you are.
We have a pretty concentrated position and yet we still find we're seeing way better performance in one part of the field by transitioning to slick water. It's not very far away, but as we move that eastern portion, higher pump rate, slick water job, with some secret sauce we're using on proppant is, we think, responsible for this significant uptick.
We're 1600 barrel a day IP30 on wells in the southeastern area and our type curve would have been 800 barrels. We have got 70 days, 80 days on some of these wells, but they are hanging in pretty well so far and it looks pretty exciting for us.
Operator
Your next question comes from the line of Patrick O'Rourke from AltaCorp Capital. Your line is open.
Patrick O'Rourke
I know you probably can't elaborate too much for competitive reasons, but in terms of the nonoperated Bakken dispositions that you are looking to do, what volumes remain? Can we expect to see it sort of piece off in the same manner that this transaction came with or are you looking to do it all as a more larger package and hit a home run there?
Ian Dundas
Home runs are good, but you can win games with lots of singles, too. We have been relatively open with people that we're willing to deal on the non-op.
There is a lot of complexity within the non-op. Lots of different operators and lots of different working interests.
When we went through the process we felt the best decision was to sell a portion of it. Could we sell other portions of it over time?
Sure. That's possible.
We talked about selling under 2% of our entire acreage position. Maybe a little more color on the non-op, that would represent about 15% of our non-operated acreage position on a volume basis we guided to 2016 volumes.
We weren't trying to be cute on that, we were trying to give people meaningful information because as you saw we've seen some pretty significant growth in the non-operated portion of that acreage block as well. That thousand barrels we spoke about probably represents 15% to 20% of that non-operated production next year.
Patrick O'Rourke
Okay. The Kansas City Royals would agree with you on that comment on the singles there.
In terms of the cost of the capital budget here at CAD350 million, have you run any stress testing? Like if you were to use 2015 service supply cost assumptions, what would that CAD350 million look like versus the cost assumptions you're forecasting forward?
Ian Dundas
I would say as a general rule, our cost assumptions and the resulting capital efficiencies are all based on our view as to what is happening to us now plus or minus. Right now in North Dakota if we were raising an AFE, all in, it would be in the mid-9s probably.
We actually assumed a slightly higher number for next year, but just slightly higher. And that's based on assumptions as we see how specific dynamics of that playing out.
I would say what is happening now is sort of what we're assuming is going to happen next year and I guess we will see. You can create a scenario that says sustained CAD50 oil creates lower cost assumptions or better efficiencies, but you can also create a scenario that says the longer we stay at CAD50 the more we destroy the capacity in the service side of the business and actually we start to see pricing pressure.
We're not trying to be heroic on those calls that are assuming Q3 continues.
Patrick O'Rourke
Okay. In the Bakken do you expect to see more of a focus down at the southeast part of the acreage?
Obviously you're having success there, but in the past up in the northwest has probably been some of your most prolific wells, just wondering how you balance that in 2016?
Ian Dundas
I would say it's not an exclusive focus on the southeast. That is just sort of how it lined up operationally in some perspectives.
We're running a pretty modest program. It is a single rig and our land situation is really good from an expiry perspective, but you still have a little bit of that at play and so you're going to see us start moving around the acreage block a little bit.
Patrick O'Rourke
Okay. Just one last question, you spend a little time talking about Marcellus differentials.
With a few of the northeast gas producers such as EQT now talking about Utica displacing some of their Marcellus assets in terms of attracting capital, does that change the way you see that play debottlenecking and the way you see differentials evolving? Have you spent any time on that?
Ian Dundas
We've spent a lot of time thinking about it. Why don't we have Eric talk about that?
Eric Le Dain
I agree. We obviously need to think about this all the time and it is a positive as people shift their spend to the Utica, in particular for the northeast Pennsylvania production of the industry as a whole and the debottlenecking that is coming through in this Q4 and then again toward the back half of 2016.
Yes, it should help narrow the differentials.
Operator
Your next question comes from the line of Kyle Preston from National Bank. Your line is open.
Kyle Preston
Ian, just wondering if we look at the next few years and assume we see recovery in commodity prices or say your Marcellus base stiff narrows, I'm just wondering how you prioritize or think about the allocation of free cash flow between call it debt reduction, production growth and potentially dividend growth in the future?
Ian Dundas
I think for our Company it's been a total return model that has been important and for that to work you need to grow. We have been managing our growth, thinking about our leverage, thinking about the sustainability of that growth and it has been, if you go back over the last three years, sort of 10% kind of growth without doing it on the back of what we would think is unsustainable leverage.
If Enerplus can provide its current dividend and grow in that 5% to 10% range over time I think we're going to do very well. Where does the next dollar go?
I think we will have to see what that looks like. Are oil prices higher, is it gas prices that are higher?
We certainly have a lot of opportunity in front of us. Unquestionably when we think about our portfolio, the North Dakota project has a lot of running room, a lot of scope and a lot of scale and it's clearly one where we see an opportunity to run at a higher pace and not over capitalize it and not drive unacceptable growth.
The balance between dividend and growth, I think right now we're all very focused on ensuring we have a capital base that makes sense that supports the dividend. My guess is the next dollar probably goes to support growth to ensure we have got cushions on that dividend.
But we will be balanced about it as we move forward.
Operator
[Operator Instructions]. Your next question comes from the line of Jason Frew from Credit Suisse.
Your line is open.
Jason Frew
I think this is another question for Eric. Eric, I thought you might -- could you walk through the factors that are informing your view of light differentials?
I ask simply because supply seems to be moderating around you and the market access seems to be improving a little bit here. So, can you walk us through some of the factors you're thinking about?
Eric Le Dain
When you speak of light differentials I assume it is focused on North Dakota. Light sweet.
What we're seeing in the market right now is a November, December market, numbers in the CAD6 below WTI range. Remember, that is CAD6 at the field point of sale.
We have about a CAD3 charge on top of that that we account for in our forecasting for trucking and gathering in the field. As we look at the balance what is going on in the market is there's a -- demand has continued strong and we've got ample capacity of both rail and pipeline out of the North Dakota region and this is contributing to incremental demand and actually flowing some days on a more variable cost basis as opposed to a full toll or above a full toll basis.
We feel our CAD8 differential that we're assuming for 2016 is appropriate and as I say the current market is a bit better than that.
Operator
There are no further questions at this time. I will turn the call back to our presenters.
Ian Dundas
Thank you everyone. It's a very busy reporting quarter.
I know everyone's busy keeping up to speed on all the moving parts. We appreciate your time today and hope everybody has a great weekend.
Thank you.
Operator
Ladies and gentlemen, this concludes today's conference call. You may now disconnect.