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Denbury Resources (NYSE:DNR)

Q1 2013 Earnings Call

May 02, 2013 11:00 am ET

Executives

Jack T. Collins - Executive Director of Investor Relations

Phil Rykhoek - Chief Executive Officer, President and Director

Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer and Assistant Secretary

K. Craig Mcpherson - Chief Operating Officer and Senior Vice President

Analysts

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Robert Bellinski - Morningstar Inc., Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Denbury Resources First Quarter 2013 Results Conference Call. My name is Lori, and I will be your operator for today. [Operator Instructions] I would now like to turn the conference over to your host for today's call, Jack Collins, Denbury's Executive Director of Investor Relations. Please go ahead.

Jack T. Collins

Okay, thank you, Lori, and good morning, everyone, and thank you for joining us on today's call. With me today in the room from Denbury are Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; and Craig Mcpherson, our Senior Vice President and Chief Operating Officer.

Before we begin the call, let me remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause actual results to differ materially from what is discussed on today's call.

You can read our full disclosure on forward-looking statements and the risk factors associated with our business in our corporate presentation, our latest 10-K and today's news release, all of which have been posted to our website at www.denbury.com.

Also, over the course of today's call, we will reference certain non-GAAP measures. Reconciliations of and disclosures on these measures are provided in today's news release.

With that, let me turn the call over to Phil.

Phil Rykhoek

Thank you, Jack. I'm happy to report we're off to a great start this year, we exceeded the consensus expectations again this quarter and that was largely due to solid tertiary production growth and we also had some very good oil price realizations. Our tertiary production increased 4% sequentially quarter-over-quarter and 17% higher than it was a year ago or first quarter of 2012. Craig is going to review that in more detail, but in summary, things are all looking good.

With a strong start, we're effectively increasing our 2013 production guidance and are expected to be in the upper half of the previously estimated ranges. In addition to the strong production growth, we also set a record for the highest ever oil premiums relative to NYMEX, largely due to the change in our production mix as we head a higher percentage of Gulf Coast crude with the sale of Bakken. With our premium price realizations at 93% crude oil, I mean [ph], our operating margins remain strong and among the highest of the peer group.

This quarter was a bit of a transition quarter for us, particularly with regard to production as we sold the Bakken assets in Q4 and get close on the Conoco and Cedar Creek Anticline assets until this -- with those funds until the end of the first quarter. Even though we had an agreement to purchase these assets in early January with an effective date of January 1, for revenue and cost purposes, we are not allowed to book production until transaction closes. While we got -- while we think it's record production, we did get the economic benefit of the first quarter net cash flow from these properties as a downward adjustment to the purchase price.

This temporary decline in total production quarter to quarter as we saw the timing of these deals was with the primary reason for lower revenue and income and flat cash flow if you compare sequential quarters. Next quarter production should be back to Q4 or higher. And Mark is also going to provide you with several pro forma numbers so you can see what the first quarter would have been had we closed on January 1 instead of the end of March.

Another notable achievement we've had is we recently began receiving and using CO2 from 2 manmade sources of the Air Products plant in Texas and Potash Corp.'s plant in Louisiana. These projects are expected to provide some 70 million cubic feet of CO2 per day to our Gulf Coast region and tertiary operations and illustrate our unique ability to use and store CO2 underground that would otherwise be released to the atmosphere. We remain encouraged by the opportunities that we see to further expand these anthropogenic or man-made CO2 supplies in the coming years.

In the Rocky Mountain region, our tertiary offerings are making progress as we expect to see our first tertiary oil production on this area later this year. We began filling up our first CO2 pipeline, the Greencore pipeline, in that region with CO2 from ConocoPhillips' Lost Cabin gas plant and expect to begin injecting CO2 in the Bell Creek Field right there on the Montana well border in the next month. We'd anticipate tertiary oil productions of field probably late third quarter.

We also began injecting CO2 in the Grieve Field using the CO2 we acquired from ExxonMobil last year, although its first tertiary oil production is not expected until 2015 as we need to repressurize that reservoir.

Last, but not the least, we also completed the redemption of our $650 million of our 9 1/2% and 9 3/4% notes. We paid bank debt, and we paid bank debt with proceeds from our $1.2 billion of 4 5/8% senior sub notes due in 2023. This offering set a record for the lowest coupon ever for a non-investment grade sub-debt offering and will save us significant dollars in future interest expense.

Bottom line, the message this quarter is that our operations are on track or ahead of projections. We've completed our series of tax efficient and accretive transactions which has converted us into a pure CO2 EOR play, which we believe offers one of the lowest risk and most compelling risk return in the industry today.

With that, I'll turn the call over to Mark and Craig and I'll give you more details on the first quarter. Mark?

Mark C. Allen

Thanks, Phil. In my comments, I'll provide some further analysis of our first quarter results, primarily focusing on the sequential change results from Q4 to Q1, as well as some of the pro forma impacts of our recently acquired Cedar Creek Anticline assets, which I'll refer to as CCA. I will also provide you some forward-looking guidance to help you update your financial models.

Our adjusted net income and non-GAAP measure for the first quarter was $123 million or $0.33 per diluted share. This was down slightly from fourth quarter adjusted net income of $137 million or $0.36 per diluted share primarily due to our Bakken transaction and then timing of the CCA acquisition as Phil discussed.

Our adjusted cash flow from operations, which excludes working capital changes, was $316 million for Q1, flat with the prior quarter. However, the prior quarter adjusted cash flow would've been approximately $358 million except for a $42 million tax payment associated with the Bakken exchange. If the recently acquired CCA assets had been included in our results for the entire first quarter, we estimate that our adjusted net income would have been approximately $150 million or $0.40 per diluted share and our cash flow from operations before working capital changes would've been approximately $375 million.

Total production for the quarter was nearly 64,000 barrels of oil equivalent per day compared to just over 70,000 BOE per day in the fourth quarter. The CCA acquisition, which closed near the end of March, added about 500 BOE per day to our first quarter production.

If you were to add the current production from the newly acquired CCA properties to our first quarter production, our first quarter production would've been over 74,000 BOE per day or about 6% higher than the prior quarter.

Craig will provide more details in our production in his comments. Our average realized oil price, excluding derivatives settlements, was about -- was almost $106 per barrel for the quarter, up about $8 per barrel from the fourth quarter. We sold our oil at an average price of over $11 above NYMEX in Q1, which was better than the over $9 premium in Q4 and our highest ever premium to WTI. Our differential was favorably impacted by the fact that a larger percentage of our production was subject to the LLS price premium in Q1.

If the recently acquired CCA assets have been included in our results for the entire first quarter, we estimate that our differential would've been over $3 per barrel lower or a positive differential of approximately $8 per barrel. The average NYMEX price premium for our tertiary production in the first quarter was about $16 per barrel, up slightly compared to Q4, with several fields receiving premiums above $18 per barrel. During the first quarter, we sold approximately 53% of our crude oil at prices based on the LLS index price. Approximately 26% of our price is partially tied to LLS and the balance of price is based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.

With the closing of the CCA acquisition at the end of Q1, we expect these percentages to return to historical levels, which would be in the mid-40% range for prices based on LLS and low 20% range for prices partially tied to LLS. As a result of this change in production mix and based on the recent decline in LLS premiums, we currently expect to realize oil price differential to trend lower in Q2 and we estimate that our oil price differential premium may decline to the mid-to low-single digits in the second quarter of 2013.

Moving on to our hedging activity. We continue to execute a strategy of protecting our oil price downside while retaining upside through cost of collars which settle primarily based on NYMEX oil prices. In addition, we've recently began adding some collars for the first quarter of 2015 that's settled based on LLS prices. The NYMEX base collars we've added for the first quarter of 2015 generally have 4 prices of $80 and average ceiling prices in the upper $90s while the floors and ceilings of the collars that's settled based on LLS are based about $5 higher than these levels.

Full details of our hedge positions are shown in the updated corporate presentation, which we just posted to our website this morning.

Our lease operating expense per BOE was in line with our expected range, coming in at around $24.50 per BOE in the first quarter. For our tertiary operations, we saw operating expense per BOE averaged about $24.70 for the quarter, an increase from about $22.60 in the prior quarter due primarily to higher CO2 expense and power but generally in line with our expectations.

We estimate that on a pro forma basis, the recently acquired CCA assets would not have had much impact on our Q1 LOE per BOE. And going forward, we expect our LOE per BOE to remain at the mid-20s per BOE range.

This rate for LOE per BOE does not include amounts for taxes other than income, marketing and CO2 operating costs, which you'll need to consider separately for your modeling purposes. G&A expense was roughly $42 million in Q1, up from $34 million in the fourth quarter. This increase was primarily due to higher employee-related costs for taxes and 401(k) match associated with the vesting of long-term compensation and bonus payments in the first quarter, as well as compensation increases effective at the beginning of the year. As stated in the fourth quarter conference call, this increase was anticipated and it is coming for our first quarter G&A to amount a little higher due to these items.

Going forward, we expect our G&A to run in the upper $30 million to lower $40 million range per quarter, with approximately $8 million to $10 million being stock-based compensation. For our first quarter G&A expense, about $8 million was stock-based compensation.

Our overall DD&A rate per BOE increased to $19.65 in the first quarter from $18.20 in Q4, primarily due to the lower production in Q1. If the CCA production has been included in the first quarter's DD&A calculation, we estimate that our DD&A per BOE would have been approximately $18.90 with most of the increase compared to Q4 due to the booking of the CCA assets at fair values. If you recall, our DD&A rate dropped by over $2 per barrel in Q4 compared to Q3 of 2012 as a result of the Bakken exchange transaction.

Looking forward, we expect our DD&A rate to range between $19 to the low $20 range for the remainder of 2013 and most likely trending up throughout the year as we place additional assets into service. Our estimates do not include us being able to book reserves at Bell Creek by year end which could potentially reduce our DD&A rate sum. That booking will depend on the timing of production response anticipated later this year.

Our effective income tax rate for Q1 was roughly in line with our estimated statutory tax rate, with about 19% of our total taxes classified as current. For 2013, we anticipate our effective tax rate will be between 38% and 39%, with current taxes representing roughly 15% to 25% from total taxes.

Moving to our capital structure. Total debt at March 31 was approximately $3.3 billion, roughly $150 million higher than the fourth quarter levels. We had $275 million drawn on our $1.6 billion bank credit facility at the end of the quarter and approximately $60 million in cash. We used the proceeds from our issuance of $1.2 billion of 4 5/8% senior subordinated notes to redeem nearly all of our 9%-plus 2016 notes and use the remainder to pay down bank debt.

Based on our current assumptions for 2013, cash flows and capital expenditures, we would anticipate ending the year with bank debt of around $150 million to $250 million, excluding the impact of any incremental share repurchases in 2013.

Interest expense net of capitalized interest was $36 million, a slight improvement for $38 million in the prior quarter. Capitalized interest in Q1 was $22 million. We expect our capitalized interest to be between $60 million and $70 million for the full year, which represents an increase from our previously guided range of $40 million to $45 million. This increase was primarily due to the projected later start-up of Bell Creek and Riley Ridge.

We expect our capitalized interest to decrease throughout the remainder of the year from approximately $20 million in Q2 to less than $10 million in Q4. Our capitalization metrics remains solid with our debt to net capital ratio at approximately 38% and our debt to Q1 annualized EBITDA at about 2.2x, which excludes the debt refinancing costs. And this is a little higher than the prior quarter as a result of the timing of the CCA acquisition. If the estimated EBITDA from the recent CCA acquisition were included in the Q1 results, we estimate our debt to first quarter annualized EBITDA would have been 1.9x.

We have increased our 2013 capital budget by $60 million to $1.06 billion, of which, approximately $20 million is for planning incremental capital associated with the newly acquired CCA properties and the remainder related to 2012 capital projects that were budgeted but not spent in 2012 and carried into 2013. If you recall, our capital spending was lower than our budget in 2012. This excludes an estimated $160 million from various items including our capitalized interest and G&G development costs and preproduction EOR startup costs. Using recent assumptions for oil prices and our other current projections, we expect to be able to fund our capital expenditures with our cash flow from operations.

Updating you now on our share repurchase program. From the beginning of 2013 through the end of April, we have repurchased roughly 4.7 million shares of our common stock for $80 million or about $16.90 per share. With these purchases, we have now purchased about 9% of our total shares outstanding since October 2011 at an average price of just over $15 per share, which effectively improves our per-share metrics by this amount. We intend to remain opportunistic with our share repurchase program and as of the end of April, we had approximately $229 million remaining as authorized under this program.

And now I'll turn it over to Craig.

K. Craig Mcpherson

Okay, thank you, Mark. Our core tertiary business started 2013 on a very strong note. Tertiary oil production was 39,057 barrels per day during the first quarter, that's an increase of 4% over the prior quarter levels. There were several key fields that had material impacts on our record level of tertiary production in the first quarter, which I'll comment on.

So I'll start with Delhi. Delhi's production was up 11% from fourth quarter levels as we saw a strong production response from the newest phase of that field. We expect production growth throughout 2013 albeit at a slower rate at Delhi until the reversionary interest is reached in the second half of the year. At that point, we estimate that our net revenue interest decreases from approximately the mid-70% range to the mid-50% range. As we previously outlined, we expect this to reduce production in the range of 1,000 to 1,500 barrels per day, which we currently expect to occur around the end of the third quarter of 2013.

Moving to Hastings. At our Hastings Field, production increased 16% from the fourth quarter level as the field responded favorably to the additional recycle compression capacity added in late 2012. We do anticipate additional growth at Hastings in 2013.

Moving to Oyster Bayou. Oyster Bayou still continues to show strong results and steady growth, increasing 23% from the prior quarter levels. We anticipate continued growth at Oyster Bayou in 2013 as the field dewaters and more wells respond to CO2.

One area of recent increased operational focus across the company is managing and optimizing our more mature EOR floods. This optimization has been a significant factor in our strong start in 2013, and a key reason to aggregate oil production from the tertiary fields I didn't discuss, specifically, were flat on a sequential quarter basis.

With the transactions we have completed over the past 1.5 years, nearly all of our current non-tertiary production now comes from fields we plan to flood with CO2 in the future. Production from our non-tertiary assets, excluding production from the Bakken area assets sold during the period, increased by about 10% sequentially to 24,766 barrels per day. This increase is almost entirely driven by the production added from the fields we acquired from ExxonMobil in December while production from our other fields was down modestly from the prior quarter. With the closing of the Cedar Creek Anticline acquisition at the end of the first quarter, non-tertiary production should increase significantly in the second quarter.

I'm pleased to say that the newly acquired properties from ConocoPhillips are performing quite well. We've identified some capital projects to perform on these assets and have increased our capital budget, as Mark mentioned, to pursue them. Our Cedar Creek Anticline production, including both legacy and the newly acquired fields, is currently between 19,500 and 20,000 barrels of oil equivalent per day. We do continue to look for opportunities to increase production by optimizing our water floods at Cedar Creek Anticline, and this is in advance of our planned CO2 flood of that field later this decade.

Looking at production on a total company basis, with a strong start to date, we now expect production to be in the upper half of our estimated ranges for 2013. In order to manage expectations, we do anticipate that our EOR and total production will be flat to modestly higher for the next 2 quarters based on the anticipated results of our EOR floods. Of course, this does exclude the contribution from the recently acquired Cedar Creek Anticline assets which are currently producing around 11,000 barrels of oil equivalent per day.

With that, I'll move to lease operating expenses. During the first quarter, operating costs for our tertiary properties averaged about $24.70 per barrel, which is up from the prior quarter but in line with our expectations. Our non-tertiary operating costs is about $24 per barrel, also increased from the prior quarter level, primarily due to the impact of our Bakken assets build. We continue to look for ways to improve the efficiency of operations and we expect to hold our operating cost per barrel flat for the remainder of 2013.

So with that, let's move to a brief review of our Gulf Coast area CO2 supply operations. In Jacksonville, we produced approximately 1 billion cubic feet per day of CO2 during the quarter. For 2013, we be budgeted 5 new CO2 wells to be drilled at Jackson Dome. We successfully drilled the first well and we're currently drilling our second.

The first well's result exceeded expectations, which may allow us to drop one of the plant drilling wells. In addition to our natural sources of CO2, we continue to make progress on securing CO2 supply from man-made sources. Please do note that we are currently injecting the CO2 being captured from both Air Products and Potash Corp. into our Gulf Coast fields. Additionally, Mississippi Power's -- Power Plant currently under construction should be completed in 2014 and could provide more than 115 million cubic feet per day of CO2 to our Mississippi tertiary operations. In addition to these 2 sources, we're in various stages of discussions with other project sponsors that could further increase our Gulf Coast CO2 sources later this decade.

Moving on to our Rocky Mountain CO2 operations. As Phil mentioned, we're currently filling the Greencore pipeline with CO2 from ConocoPhillips' Lost Cabin gas plant, and we expect to commence injecting CO2 in the Bell Creek in the next month or so. We expect first tertiary oil production from the field 3 to 5 months after first CO2 injection, depending on how fast the CO2 travels through the reservoir rock.

We also started 4 CO2 injections into Grieve Field in Wyoming with first oil production expected in 2015 when that field reaches the appropriate rock operating pressure. We do expect to obtain additional CO2 supplies from ExxonMobil's Shute Creek facility in the future. And we're working to secure pipeline interconnect between the Greencore pipeline to the pipeline that transport CO2 from Shute Creek. This pipeline interconnect is important to us because it will significantly reduce the cost and time to deliver CO2 from Shute Creek to operate at Bell Creek and Hartzog Draw Fields. At the Riley Ridge gas processing facility, we continue to expect natural gas and helium production to begin during the third quarter of this year.

So in summary, our CO2 supply and transportation operations are performing well and are on track to meet the needs of our expanding tertiary oil production operations.

With that, I'll turn it back over to Jack.

Jack T. Collins

Okay, thank you, Craig. Lori, that concludes management's prepared remarks. Can you please open the call up for questions?

Question-and-Answer Session

Operator

[Operator Instructions] And the first question is from the line of Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

I have a couple of quick ones. First on Cedar Creek Anticline. You mentioned, I guess, there's -- I just want to clarify, so $20 million of the incremental $60 million in CapEx is going to go to kind of capital projects there?

K. Craig Mcpherson

Correct.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. And can you, I guess, quantify -- I know you've spoken about the decline rate on the conventional fields. What are you trying to do and maybe what's the best case scenario on how you can mitigate declines before you begin the floods?

K. Craig Mcpherson

Well, we're doing that throughout the fields. Well, let me just take -- I'll speak to Cedar Creek Anticline to start with, and then we'll -- Cedar Creek Anticline, we see a lot of opportunities to optimize that waterflood, and so that's swept that additional CapEx going forward. In a newly acquired field, we see opportunities to enhance the waterflood. So what that means is we are cleaning out all the wells to get more water passing through the reservoir. The higher the water rate, the higher the production rate, so that's the objective there. And then on the EOR floods, we're optimizing that just by better management of the CO2 traveling through the rock, and so that's paying close attention to what we call conformance, especially since the CO2 is going into the horizons with the highest oil percentage. We're also working on keeping our compressor up time higher, and so the more our equipment works, the higher our production.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. And then quickly on Bell Creek, sounds like you feel -- you could see some production response by the end of third quarter. So how, if any, should we think about the fourth quarter contribution to production?

Phil Rykhoek

Well, I mean, it's not going to be material just because it's starting now kind of late. So we expect it to ramp up somewhat similar to the way Tinsley has responded over the years. So it should have some decent growth, but I mean, as far as the impact on 2013, it will be somewhat negligible.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay, okay. And then I just had one final one on the production guidance. I didn't quite catch it when you're talking about, through the quarters. I guess, Craig mentioned it. Can you repeat what you're talking about as far as EOR production over the next couple of quarters?

Phil Rykhoek

Yes, I mean, I basically mentioned, we expect the next couple of quarters of EOR to be relatively flat, maybe a slight growth, and so we're just trying to kind of manage expectations and then we expect a little bit more growth in the fourth. So yes, just trying to manage expectations.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. And then lastly, can you -- what would drive that fourth quarter growth?

Phil Rykhoek

We'd expect a bit more growth particularly at Heidelberg, although, again, continued growth at the fields that are growing, Hastings, Oyster Bayou. But I think the bigger jump is probably anticipated -- Heidelberg, particularly, in the Christmas formation. And also, you get a low bid from Bell Creek although it's not a big number but it helps fourth quarter. The offset is you will lose some production at Delhi. And we expect the growth to be higher than what we lose.

Operator

And our next question from the line of Pearce Hammond with Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Phil, can you catch us up on your thoughts about maybe taking some of your mature EOR properties in the Gulf Coast and maybe putting them into either royalty trust or an MLP or some sort of vehicle like that?

Phil Rykhoek

Well, we're just kind of looking at all the options. I mean, I think that -- as you know, we've stated that we expect to have free cash flow in 2017 and that's what we're driving toward and I think conceptually, if we could figure out a way to bring that forward to 1 year or 2, we'd love to do that. And so that's potentially where our MLP or something else might come into play. So we're trying to do that. We have just manage expectations, I think it will take us several more months before we come up with a plan, and for now, we still expect free cash flow in 2017. If we can better that, we will try.

Pearce W. Hammond - Simmons & Company International, Research Division

And then, if you could compare and contrast some of the challenges, whether it be terrain, weather, whatnot between Rocky CO2 operations and Gulf Coast CO2 operations. And obviously, you're increasing your level of activity in the Rockies. And is there any learning that's occurred that you might find useful to either accelerate things or to make things run smoother at the Rockies?

K. Craig Mcpherson

It's Craig. Maybe we'll start with similar. We know that CO2 EOR works in the Rockies, and there's several fields there that CO2 EOR works quite well. We know that it's admissible and so we're highly confident that just like it worked extremely well in the Gulf Coast in the Permian Basin that it does already prudent works extremely well in the Rockies. So the process is the same, the process will be successfully applied across the Gulf Coast in multiple fields. That is the same process we will apply in the Rockies. So what is some of the differences in general, and this is -- actually, this is not applicable to Bell Creek but it is to the others is, the rock is tighter, okay, so you're talking about lower permeability, which -- what it means is it just takes a bit longer for the CO2 to travel to the rock. The mechanism of the contacting oil grabbing ahold of that oil and carrying it for the producing oil is exactly the same. It just takes a bit more time and so we factored that into our forecast. From an operability standpoint, related challenges are weather and the fields are larger, and so there's a geographic spread to that, so that creates some operational differences. Frankly, more time in a truck to get from well to well, but beyond that, the process is the same. That's it.

Operator

And our next question, from the line of Robert Bellinski with Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

I was just wondering, can you discuss some of the opportunities and challenges that you're kind of currently seeing related to acquiring additional oil fields along the pass of the Greencore pipeline?

Phil Rykhoek

Well, we're always looking at deals, so it's always extremely difficult to forecast. And in fairness, we're probably not pursuing it quite as much as we have in the past because we have inventory of projects that can give us growth for a decade. So there's no pressing need to buy things. So we'll probably take a little bit more opportunistic view, but if properties were to become available or we could cut a deal, I mean, we would still consider that, obviously. And anything we'd look at would be in our 2 regions within reach of our infrastructure. There are a lot of fields along the Greencore pipeline and in other parts of Wyoming, so there's -- there are a lot of targets there. If you look at our slide show, we kind of showed you where the fields are with the green dots. But -- a lot of opportunity, but I think we're taking a little bit more opportunistic look at it, at least for 2013.

Robert Bellinski - Morningstar Inc., Research Division

Okay, and then can you quickly just kind of walk through the costs and economics associated with the CO2 capture and injection projects in the Gulf Coast?

Phil Rykhoek

Economics? Well, we have great economics. If you flip through our slide presentation for instance, we talked about -- I think I mentioned it earlier, we have the highest margin of our peer group, or at least we did in 2012. I think we're continuing to, largely because of our premium pricing and heavy focus on oil. We tend to have low S&D costs if you look at the last 3 years. Adjusted F&D, we were one of the lower ones, other than maybe a gas company or 2 might beat us, but at least the oil guys that were pretty low, which you put those 2 together, it means you have a capital efficiency. Another point, we also have pretty low breakeven economics. So they all point to great return, particularly relative to the risk in EOR, and quite candidly, that's why we made it our core focus. It was the place where we're making the most money.

Operator

And our next question, from the line of Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Mark, I was wondering if you could help us with what the pro forma PV-10 would look like post the CCA acquisition? I think in your previous disclosure, you talked about maybe a $1.1 billion uptick. Is that...

Mark C. Allen

Yes, about $1.1 billion. Yes, it was the number we -- I've put out previously...

Yes, about $11 billion adjusted PV-10.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. Next question, Mark, I was wondering maybe if you could walk us through your next 2 floods -- your next 2 big floods at Webster and Hartzog withdraw? When do you plan to begin the floods? And preliminary thoughts on what part of 2015, 2016 we could start to see some tertiary production.

Mark C. Allen

Well, Webster's scheduled for 2015. I think what we'd probably anticipate is injections in the first half of the year and depending on the timing of the response, probably, the best case would be production like that year, or initial production.So usually, when we use dates or years, that's kind of the tentative timetable we hope to start injections in the first half, and normally, sort of 6, at most, 9 or 12 months for response. So Webster's 2015. That moved ahead of Conroe. And Conroe's now 2017 in the Gulf Coast and then Thompson's after that at 2019. In the Rockies, Hartzog, we're assuming we can get the CO2 and use the Exxon CO2 and get an interconnect with Anadarko. And assuming that all works as planned, which we think is very likely, we would plan to start injections there and have production in 2016. That's all.

Arun Jayaram - Crédit Suisse AG, Research Division

And last one for me, is you did not express confidence in the upper end of the range on production. You see -- is this correct? Maybe a little bit more of a flattish with some slight growth in Q2 and Q3 with a bump-up in Q4 despite the fact that you have the reversionary interest. Is that how you kind of see on a quarterly run rate things kind of play out from production basis?

Mark C. Allen

Yes. Yes, that's correct.

Operator

And our next question is from the line of Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just had 2 quick ones. One, with Bell Creek, obviously, I understand you're not going to have too much production to speak of, but you will be able to book reserves at the end of this year, I assume, because you will, at least, have the response, and you'll have some production online.

Phil Rykhoek

Well, it depends on the timing of the response. If you recall, they usually like to see 3 to 6 months of production before the engineers, which, by the way are independent, would let us book the reserves. So we might, we might not, it's a little hard to say because it all depends on timing and the rate of the response.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. Understandable. And then just with the industrial facilities, obviously, they're going to add $70 million, as you said. Does that take a while as they bring the plants on to get to that level? And if so, just kind of how long that time frame, at least, is estimated to be? I guess there could be moving parts, but is it a slow steady process to get it up to full speed as their plants get up to full speed?

K. Craig Mcpherson

Well, no, it actually happens pretty quick. So if contacts -- we're at $60 million a day right now from those 2 sources. So our process is full board at $50 million and we're getting $10 million already out of Potash.

Operator

And our next question, from the line of Hsulin Peng with Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

I may have missed this, but I think you mentioned the pipeline interconnect in the Rockies. I was wondering if that -- the cost of that particular project, and also, whether that would -- that could help you move up your -- some of your tertiary floods in the Rockies.

Phil Rykhoek

I don't have the precise number of that interconnect, but it's minor dollars, I mean, I think, you're talking just a few million.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So it's not really much?

Mark C. Allen

No.

Phil Rykhoek

No, no. They're actually very close together, so it's just connected. And as far as the timing or impact on timing, that's factored in to our projection of flooding Hartzog in 2016. You think we could start Hartzog a little sooner, but we still do have to get a permit to put the line going from Greencore to [indiscernible] and that really is the bottom there, because the part that takes a little while is getting approval, environmental approval, put that line in. So -- but we believe 2016 is a reasonable date.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then just as a follow-up to the Greencore pipeline. You talked about potential acquisition opportunities along the -- in the Rockies along the pipeline. Now I know you guys did something -- did similar things in the Gulf Coast, but I'm just wondering, given the timing of the pipeline buildout, if there is an optimal time doing the infrastructure buildout maybe right before it's completed to be looking at potential consolidation opportunities.

Phil Rykhoek

Well, I mean, probably the optimal time would be -- yes, right when it's completed. You have extra CO2 and then you can start the process right away, but it never works that way, so you have to just kind of adjust. And unfortunately, we don't get to negotiate with ourself, it takes a willing seller. So the timing is hard to forecast.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, understood. And then last question, with the 2013 production guidance to the upper half, I was wondering if you can comment on which particular tertiary fields or is this combination of all of them that's helping you guys feel more comfortable to the -- pointing to the upper half?

Phil Rykhoek

Well, I think the biggest thing is we're 39,000 now. So obviously, we're not too far from the upper end today. We do expect the next 2 quarters, as we mentioned, to be relatively flat or at least very, very modest growth. So -- but what's happened is, the fields that are growing, they are expected to grow, although the growth rate is expected to slow down a little bit at Delhi and Hastings. And part of the biggest wildcard is what happens with some of the mature properties. We have, as Craig mentioned, it was very strong and that we held the mature properties pretty flat quarter-to-quarter, but we don't necessarily think we can continue to do that. So that's kind of what's happening in the second and third. We expect to have a little slippage there, and we'll see how that goes. Perhaps we can beat that, but that's kind of I think what's in the forecast.

Operator

[Operator Instructions] We'll go next to the line of Mike Scialla with Stifel.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Craig, I might have missed it. Did you give an update on the tertiary fields that were -- shown a lot of growth in the first quarter? Did you mention Hastings, and if not, could you tell us what Hastings did in the first quarter?

K. Craig Mcpherson

Hastings production has grew -- I forgot what percentage[ph]-- but Hastings production grew primarily as a result of the increased concession[ph] that we added in late third...

Phil Rykhoek

[indiscernible] It was 3,409 in Q4 and 3,956 in Q1.

K. Craig Mcpherson

So 16%.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. And you mentioned the LOE being up in the first quarter, primarily due to the sale of the Bakken assets. So is the first quarter a good run rate for the rest of the year?

Mark C. Allen

Yes, we estimate it to be in the mid-20s. So that's in line with our expectations.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, and at Jackson Dome, you mentioned that the first well this year came in better than anticipated. I assume that was a rate well and how many of the 4 for additional wells that were contemplated are exploration wells?

K. Craig Mcpherson

Well, so first of all, it -- this first well was a reserve add well, and actually, we believe it could be a quite a significant reserve. Our pay was more than double what we expected as a new part of Jackson Dome area, so it's a -- it'll be reserve add well. So of those 5 wells, I believe, 2 or 3 were reserve add wells planned, so we are more than well positioned to get our reserve as what we planned for this year at Jackson, very pleased with this well.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

That's great. Any sense for what the reserve addition might be at this point from that well?

Mark C. Allen

Well, we can't evade this, but we're not quite ready to give a number yet, but I guess -- I mean, it could be up to a few hundred BCF.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

TCF potential? Did I hear that right?

Mark C. Allen

A few hundred BCF.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

A few hundred BCF, okay. And before you finalize that, is that going to take another well or do you just need some time to see how the production performs?

K. Craig Mcpherson

We just need to get it online. We've -- so this is based off of a -- we've drilled it, we've logged it and we're completing it. So it'll be on production here shortly. When we see some production response, we'll feel highly confident in booking it.

Operator

And our next question from the line of Richard Tullis with Capital One Southcoast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Phil, I know you mentioned that current projections are for a free cash flow positive 2017. Could you kind of outline what sort of CapEx number going forward you're looking at before you get to that point, and also, the infrastructure commitments or projections for the CO2 operations over the next couple of years?

Phil Rykhoek

Sure. If you recall from our slide show, we show, of course, that's just EOR, but that's obviously the bulk of our expenditures. We anticipate that CapEx grows about $1.3 billion plus or minus a little bit in 2016. And actually, it's kind of a steady growth, it may not be a straight line. And then you might have another 100 or 200 for other things. So probably 1 5, 1 5ish. And then we expect it to decline from that point forward. What's happening is that includes the anticipated pipelines and infrastructure and so forth, particularly in the Rockies. We have -- we only have probably, what, about, 1/3 of that pipeline built to maybe not even 1/3, maybe 1/4 with the Greencore's and we still have to connect it down to Riley Ridge and ultimately up to CCA. And secondly, we need to spend a little bit more money at Riley Ridge to get the -- sweetener plant online and drill a couple of additional wells, actually, I think 3 additional wells between now and 2017. So that's -- conceptually, the Gulf Coast is already building on free cash even though it's still growing and we're still investing and expanding into new floods. But of course, the Rockies is a user of cash at this point, because we don't really have any EOR production up there yet. Our first production will be from Bell Creek. So that's kind of conceptually what's happening.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. I know the oil accounted for, I guess, by 93% of production 1Q. Does that change any, going forward, now that CCA will be fully reflected in the quarterly production?

Mark C. Allen

It stays pretty consistent when I see go up a tad, so I think CCA's primarily oil, I think 99% oil and liquids, so it should remain very strong.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And then lastly, on the current tax. I missed it a little early. What did you mention the new guidance is there?

Mark C. Allen

We're estimating about 15% to 25% to our total taxes being current. We still have some -- the finalization of our escrow account or our like-kind exchange, we had about $50 million or so remaining in there. So we think most of that will be going toward settlement of the final purchase price adjustments. To the extent it does not, we could have some incremental tax leakage. But at this point, we're not estimating that to be significant.

Operator

And our next question is from the line of Michael Glick with Johnson Rice.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Just a couple of questions on timing. Is there any update to the timing of the startup of Riley Ridge or the CO2 pilot at CCA?

K. Craig Mcpherson

We're still on track for the first part of the third quarter to start that plant up, so things are on track.

Phil Rykhoek

Yes. The pilot, we're still kind of evaluating that for sure, but it wasn't scheduled to start until late this year, early next year. So we have a bit of time on that. We're still kind of evaluating the best way to do that. With the addition of the Conoco assets, it may change our plan just a little bit.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Okay. And then just in terms of your guidance. Did you guys build any hurricane downtime into that?

K. Craig Mcpherson

We do not. We're pretty far away from the coast. So unless -- really the only exposure, probably, is a bit at the Oyster Bayou from a storm surge that we would have to shut in for that. But no, nothing material.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

And then just real quick on the Heidelberg. What kind of performance have you seen from the Christmas zone thus far relative to your expectations?

K. Craig Mcpherson

We are very pleased with our early response with the Christmas at Heidelberg. Early days, but initial results are on track to and, perhaps, maybe a little bit ahead of where we thought it would be.

Operator

And our next question will be from the line of Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Just kind of looking at the schedule you all have in your Page 27 of your deck. There is -- it looks like Heidelberg, Oyster Bayou and Tinsley are right around their max forecasted rates. So I guess, kind of taking your comments about production being kind of flattish the next quarter 2. So we're really looking at Hastings is just kind of where -- I'm inferring Hastings where the bulk of the growth is coming from. How many additional patterns are you looking to bring on or are you looking to bring on more patterns in Hastings things before the -- over the next 2 quarters?

K. Craig Mcpherson

I don't have the exact number in my head, the additional patterns that Hastings will bring on. It's several. Well, actually, it's just increasing the -- waiting for the flood response at Hastings. The CO2 is going in them and just waiting for that response. I mean, it's kind of a down dip pattern. I don't actually have the exact number in my head. We do expect Hastings production to grow through 2013. But it might also, we do expect Oyster Bayou production to grow as well through 2013.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Oyster Bayou looks like it's in the bucket for up to 5 mb/d kind of max peak rate and you're just about half there right now. So, okay. So we could then have perhaps a little bit of growth there for the next couple of quarters depending on how the -- how everything comes in.

K. Craig Mcpherson

That's correct.

Phil Rykhoek

Yes, Oyster's at 20, 22 50 or 22 52 to be precise this quarter, so you got a little room there. It's been on a very steady incline, so it's doing very well.

Operator

And our next question, from the line of Noel Parks with Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Just a few things. Heading back to the Cedar Creek Anticline for a minute. Now that you're at the point that you're starting to get your arms around the new additions, the new acquisitions there, can you characterize sort of the status of those fields in terms of, I guess, maybe how neglected they were relative to, say, when you took over the rest of the Anticline fields from Encore a few years ago?

K. Craig Mcpherson

It's Craig. I'll take a shot at it. The Copperfield's assets were very well run and in good shape and so we're pleased with that. That being said, it was probably undercapitalized, and so there's some opportunities there to pursue. And so hence, while we want to spend a bit more money in the Copperfield's assets primarily to get to the higher volume of water to get the higher volume of oil, we see that as a low-hanging fruit. ConocoPhillips is pursuing that. We are going to accelerate the pace at which we pursue that. So a really great asset, probably, a little bit better than we planned on. So we like what we see, we're just -- frankly, we're just a month into it, so learning more of it. The more we learn, the more we like it.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great. And along the same lines, so with those fuels added, I guess, I'm just trying to get a sense of the far north of this deal, which, of course, will take the -- it'll longer to get the pipeline CO2 up there versus the south of the field. Does adding the CCA assets into the mix -- does it really shift the order of how you might attack the different parts of the Anticline? And I guess, I was thinking about maybe where the relative pressures are in the stuff you acquired versus the things you've held longer and you've done more work on and done more in the waterfloods on and so forth?

K. Craig Mcpherson

Quick answer is, yes, it will. And it'll enhance it. In fact, we're working to that, changing the sequencing, but the bottom line is, we'll enhance it. We'll start further south with these new assets. They have waterflooded very well, and without going into all the details, we believe they will. The net -- there are many oil that's high there. It's got a zone that we believe is -- will be very responsive to CO2. So we actually believe our EOR economics for CCA have been enhanced from a return standpoint and an efficiency standpoint by the acquisition of ConocoPhillips assets.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great, thanks. I think the -- the only other thing, I guess, just -- I know that for quite a while now, you guys have been real cautious on setting expectations for the LLS premium persisting over the long haul. I'm wondering just kind of what your thinking is right now, especially as you start to see how the -- sort of with the Bakken production and the way infrastructure is kind of remaking itself to get oil to the coast and so forth, are you still inclined to just assume that's a temporary phenomenon? Or are you getting a little bit more optimistic for the long term?

Mark C. Allen

Well, I think bottom line -- I don't know if anybody is for sure, but we obviously look at it. We do think there will remain some differential but we do think, as others do, I think, it'll likely to contract here over time. And so I guess, just looking at some of our hedging, we have started to hedge some of it in LLS. The market's gotten a little bit more wide open, and I think, from a hedging standpoint, you're -- like to look to your price index generally to alleviate some disconnect. But -- and as we're really just bringing in the mix, trying to offset that to some degree, but we do see it remaining somewhat but we do think it will contract over time.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Do you think it's -- you're thinking a couple of years is reasonable to expect that it could last? I'm not trying to pin you down or anything.

Mark C. Allen

We hear a lot of different ones a week. I really don't know. I mean, we -- I think a lot of people already projected it to come in quite a bit beyond where it has, and so we are opportunistic with it. We don't try to get too cute, but we'll continue to watch it and take advantage of it as we -- as best we can.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

And the only reason I ask is just, if we did foresee a scenario where they continue to diverge, then had to tend their old $10 barrel difference between the Rockies and the Gulf Coast. I'm just thinking about whether that changes the calculation for small fields in the Gulf Coast versus dollars spent in the Rockies build. I know we're talking over a long time frame, so it's not going to be but so precise but that was kind of what I was thinking about.

Phil Rykhoek

Yes. I mean, that's -- the nature of our floods, that's one thing that really distinguishes from the shale play. We -- they're such long life assets that one year or 2 years doesn't really make all that much difference to rates of return. There is a pretty big disconnect in pricing today or there has been, historically, it's starting -- LLS is starting to come down. And I think most people expect it to go back to historic levels by end of this year. It's probably consensus, but it doesn't mean it's right. But it appears to be moving in that direction. So we're going to be pretty conservative in our forecast and we're not -- at least for internal forecasting, we don't assume that it stays high.

Operator

And I'll now turn it back to our speakers for closing remarks.

Jack T. Collins

Okay, Lori. Thanks again to everyone for attending and participating in today's call. Management will be presenting at a number of investor conferences over the next few months. A full schedule of these conferences are available on our website. Also, the slides for this presentation and webcast will be accessible in the Investor Relations section of our website as well. If you're attending any of these conferences, we hope to see you there. And lastly, we currently plan to report second quarter 2013 results on Tuesday, August 6, and hold our conference call that day at 10:00 a.m. Central. Have a great day.

Operator

Thank you. Ladies and gentlemen, this will conclude our conference call for today. Thank you for your participation and for using AT&T Executive TeleConference Service. You may now disconnect.

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