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Denbury Resources (NYSE:DNR)

Q4 2012 Earnings Call

February 21, 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

Craig J. McPherson - Chief Operating Officer and Senior Vice President

Analysts

Arun Jayaram - Crédit Suisse AG, Research Division

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

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

David W. Kistler - Simmons & Company International, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

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

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

Operator

Good day, ladies and gentlemen, and welcome to the Denbury Resources Fourth Quarter 2012 Results Conference Call. My name is Lori, and I will be your operator for today. [Operator Instructions] Later we will conduct a question-and-answer session. [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 proceed, sir.

Jack T. Collins

Okay, thank you, Lori, and good morning, everyone, and thank you for joining us on what's a busy earnings day. So with me on today's call 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, I'll turn the call over to Phil.

Phil Rykhoek

Thank you, Jack. I'm happy to report that our Q4 financial results were well ahead of consensus expectations, largely driven by strong tertiary production growth and an improved NYMEX oil premium, ending the highly productive year on a strong note.

Craig's going to review tertiary production in more detail, but in summary, we're very pleased with how we finished the year. This strong fourth quarter gives us a great start for 2013 and makes us optimistic about our full year tertiary production outlook.

For those of us that follow -- for those of you that follow us regularly, you know the last 12 months have been a very active period for Denbury. I thought I might quickly highlight some of these recent successes.

On the transaction front, we've completed our announced deals with over $4 billion of aggregate value if you count both the purchase and the sale. So what's the net result of that? First, we sharpened our strategic focus on enhanced oil recovery, where we have a strategic and competitive advantage. Today, nearly everything we own is either a current EOR flood or is part of planned future EOR operations.

Secondly, we increased our unproven EOR potential by nearly 210 million barrels, which even with the Bakken divestiture, results in a net increase in our unproven potential reserves. Further, they are now EOR potential barrels, which we believe will add more value to Denbury than the potential barrels that we sold. We now have over 650 million barrels unbooked EOR potential in our inventory, which gives us more than a decade of growth and will create substantial value for our shareholders.

Third, we nearly replaced the production of the sold assets with that from the acquired or to be acquired assets. Fourth, we exchanged proved reserves with a high proved undeveloped component for reserves that are nearly all proved developed, which significantly increases free cash flow. To be a little more specific, the Bakken assets had over $1.7 billion of future development cost associated with them, and the acquired assets have less than $100 million of future development costs.

Fifth, we have increased our Rocky Mountain CO2 reserves by 1.3 trillion cubic feet and up to 115 million a day of deliverability. Lastly, we did all this, in a tax-efficient basis. Our latest announcement, the pending transaction with Conoco, wherein we're buying their CCA assets for $1.05 billion, allowed us to defer about $400 million of taxes, gives us nearly 11,000 barrels a day of oil production and 60 million to 80 million barrels of potential EOR reserves.

It increases our interest in an area that was already our largest in the Rocky Mountain region, which will allow us to benefit from economies of scale of CCA and leverage our planned CO2 transportation infrastructure. In fact, if you'll note, all of the acquired future EOR fields are very close to existing or planned pipeline infrastructure, allowing us to amortize that cost over millions of additional barrels, improving the returns on these incremental acquisitions.

So bottom line, this collection of M&A transactions could work out probably even better than we'd hoped in our company transforming transactions. If you want more details on the transaction, I encourage you to review our updated investor presentation.

Another notable recent development is we began receiving our first man-made, or anthropogenic CO2 from Air Products in Texas. CO2 deliveries are expected to approach 15 million cubic feet per day, when their second train comes on later this year. This project illustrates our unique ability to use and store anthropogenic CO2 that would otherwise be released to the atmosphere. We're highly encouraged by the opportunities we've seen to further expand our anthropogenic CO2 in the coming years.

On the finance side, we recently issued $1.2 billion of senior sub notes with a coupon rate of 4 5/8%. We're told that this interest rate was the lowest on record for a noninvestment grade sub note offering, which illustrates the market's confidence in our company and our outlook.

A few weeks ago, we released our proved reserves, which Craig's going to touch on in a minute. One number I'd like to point out from that report is that our proved PV-10 at year end, inclusive of the pending CCA transaction with Conoco, was about $11 billion. If you subtract our net debt and divide it by our shares, you'll find a pretax proved net asset value of over $20 a share.

So to put it another way, if you were to purchase our stock today, you'd effectively get our 700 million barrels of unproved reserve potential for free, reserve potential that will give us consistent production reserve growth for more than a decade. Also given the unique characteristics of our strategy after 2016, we expect our capital expenditures to begin to decline gradually over time, while production continues to grow, thereby generating growing amounts of free cash flow.

So although our stock has recently performed well, we believe it still remains a bargain and continues to trade below peers on a net asset value basis. It's been an impressive 12 months, and we are now situated to focus on what we do best, CO2 Enhanced Oil Recovery, which we believe offers one of the lowest risk and most compelling rates of return in the oil and gas industry.

So going back briefly to Q4. As you'll note, our adjusted net income and adjusted cash flow were up, were both up on a sequential basis, even though we lost some production in the month of December with the Bakken sale. We had strong growth in tertiary operations, with 8% sequential growth and perhaps, maybe a bit of a surprise, were our strong oil price realizations. With our increased exposure to Gulf Coast oil prices following the Bakken exchange, our average realized oil price premium reached a new record level in Q4. With these premium price realizations, with our 90%-plus crude oil production stream and continued focus on controlling costs, our operating margins have been one of the highest in our peer group, and we expect this to remain the case going forward.

But let's have Mark and Craig give you more details on the numbers. Mark?

Mark C. Allen

Thanks, Phil. In my comments, I'll provide some further analysis of our Q4 results, primarily focusing on the sequential change and results from the third quarter of 2012. I will also provide some forward-looking guidance to help you update your financial models.

Our adjusted net income, a non-GAAP measure, for the fourth quarter, was $137 million or $0.36 per diluted share. This was up from third quarter adjusted net income of $127 million, or $0.33 per share primarily due to higher oil price realizations, lower DD&A and lower average diluted share count.

Our adjusted cash flow from operations, which excludes working capital changes, was $316 million for Q4, down from $350 million in Q3. However, if you adjust for the higher current taxes in Q4, which was all related to the Bakken exchange transaction, our adjusted cash flow from operations would have been $358 million, which was a slight increase from the Q3 number.

Total production for the quarter was 70,116 barrels of oil equivalent per day. Excluding the Bakken property sold, production was 60,052 BOE per day, an increase of 7% sequentially, driven primarily by the tertiary production growth and new properties acquired in the Bakken exchange.

Tertiary production averaged 37,550 barrels per day in Q4, a new record, and it averaged 35,200 barrels per day for the full year 2012. Our annual tertiary production level put us squarely in the upper half of our 2012 guidance range.

As indicated in our news release, we are keeping our total 2013 production estimates unchanged at the range of 68,700 BOE per day to 71,700 BOE per day, which assumes the recently announced CCA acquisition closes near the end of the first quarter of 2013. Please note that estimated production from the CCA acquisition will not be included in our financial results until the transaction closes.

Our average realized oil price, excluding derivative settlements, was up about $4.50 from the third quarter to about $97.60. We sold our oil at an average price of $9.43 above NYMEX in Q4, which was significantly better than the $0.80 premium in Q3. On a pro forma basis, if we were to exclude the Bakken assets from our Q4 numbers, our average realized oil premium would have increased to $11.65 per barrel. All of our current tertiary production is in the Gulf Coast region, with the majority of it being sold on LLS-based indexes.

The average NYMEX price premium for our tertiary production in the fourth quarter was $15.57, with many fields receiving premiums above $17.50 per barrel. Our Rocky Mountain region pricing also improved significantly as the differential for our Cedar Creek Anticline production improved from the prior year quarter's discount of roughly $9 per barrel to an average, very small discount this quarter.

During the fourth quarter of 2012, we sold approximately 44% of our crude oil at prices based on LLS index prices. Approximately 22% of price is tied to a combination of LLS and other indexes, and the balance of that price is based on various other indexes tied to NYMEX, primarily in the Rocky Mountain region.

Moving on to our hedging activity. We continued to execute a strategy of protecting our oil price downside, while retaining upside through costless collars, which are based on NYMEX oil prices. During the fourth quarter, we layered on collars for the back half of 2014, with a floor price of $80 and a weighted average ceiling of $97.50. Full details of our hedge positions are shown in the updated investor presentation we posted to our website this morning.

Our lease operating expense was $139 million, up roughly $9 million from the prior quarter, primarily due to higher workover costs and increased CO2 purchases for our newest floods at Oyster Bayou and Hastings. On a per BOE basis, our lease operating expense was $21.61 in Q4 as compared to $19.49 in Q3, with the increase primarily due to the sale of the Bakken assets during Q4, which had a lower operating cost.

On a pro forma basis, if you exclude the Bakken assets for the entire fourth quarter, our lease operating expense per BOE would have been $24.33. For our tertiary operations, lease operating expense per BOE averaged about $22.60 for the quarter, an improvement from the $23.50 in the prior quarter. With the sale of our Bakken assets, we expect our lease operating expense per BOE to average in the mid-20s range for 2013, a little higher than our Q4 pro forma rate of $24.33.

It's important to note that this rate does not include taxes other than income, marketing and CO2 operating costs, which you'll need to consider separately. G&A expense was roughly $35 million in Q4, down from $38 million in the third quarter. Our fourth quarter G&A expense, about $6 million, was stock-based compensation. For 2013, we expect G&A expense to be in the upper 30s to mid-$40 million range each quarter, with approximately $7 million to $10 million of that in stock-based compensation. I would expect our first quarter to be towards the higher end of that range, due to bonus and long-term incentive payouts.

Our overall DD&A per BOE decreased to $18.20 in Q4, from $20.45 in Q3, primarily due to the Bakken exchange. As a result of the Bakken exchange, our depletable cost decreased, and a significant amount of future development cost related to the Bakken were removed from our calculation. With the completion of the Greencore pipeline and the expected closing of the CCA acquisition, we expect our DD&A rate to move back into the $20 to $21 per BOE range in 2013.

Our effective income tax rate for Q4 was approximately 41%, above our estimated statutory rate of 38.5%. This was primarily due to additional state income tax expense recognized as a result of the Bakken transaction and the impact of changes in our estimate of certain tax benefits.

For 2013, we anticipate our effective tax rate will be around 38.5% to 39%, with current taxes representing roughly 15% to 20% of total taxes. However, current taxes could be somewhat higher, depending on the final adjusted purchase price for the CCA acquisition. We will incur incremental cash taxes on the CCA acquisition if our adjusted purchase price is less than the $1.05 billion put into the qualified trust account. Since the operating cash flow between January 1 and the closing date will result in a purchase price adjustment, we believe this could result up to $10 million in incremental cash taxes.

Moving to our capital structure. Total debt at December 31 was approximately $3.1 billion, in line with third quarter levels. We had $700 million drawn on our $1.6 billion bank line at the end of the quarter, and nearly $100 million of unrestricted cash. With our recent issuance of $1.2 billion of 4 5/8% senior subordinated notes, we intend to redeem all $651 million of our 9-plus percent 2016 notes and use the remainder to repay the bank debt. By March 31, we expect to have redeemed all but $38 million of our 2016 notes, which we are not able to redeem until early May.

This was a significant transaction for us, as it allowed us to more than cut in half the interest rate of $651 million of our debt to about 4.6%, from a weighted average rate of about 9.7%. After considering the premiums to early retire these notes, we anticipate we will have roughly $500 million available to pay down our bank debt.

We also expect that we will have a charge in the first quarter of approximately $45 million related to the early redemption of the 2016 notes, with approximately $10 million of that amount due to the write-off of debt issuance costs.

Based on our current assumptions for 2013 cash flows and capital expenditures, we would anticipate that our bank debt should be around $100 million to $200 million, depending on timing of expenditures and incremental share repurchases in 2013. Interest expense, net of capitalized interest was in line with prior quarter levels of approximately $38 million. Capitalized interest in Q4 was $20 million.

We expect our capitalized interest to be between $40 million and $45 million for the full year 2013, with estimated quarterly capitalized interest decreasing throughout the year from roughly $15 million in Q1 to $5 million in Q4, depending upon when certain assets are placed in service.

Our capitalization metrics remain solid, with debt to capital ratio of approximately 38%, and our debt to Q4 annualized adjusted cash flow and EBITDA adjusting for the current quarter tax impact to the Bakken exchange at about 2.1x and 1.9x, respectively.

Our 2013 capital budget remains at $1 billion, which excludes an estimated $125 million for various items, including capitalized interest, G&G exploration and development cost, and preproduction EOR start-up cost. Using current oil prices and assumptions, we expect to be able to fund our capital expenditures with our cash flow from operations.

During the fourth quarter, we repurchased roughly 14.5 million shares of common stock for $226 million, or roughly $15.60 per share. And thus far in the first quarter, we have repurchased an additional 3.5 million shares for $60 million, or an average of $16.73 per share. Since the commencement of the share repurchase program in October 2011, we have purchased about 9% of our total shares outstanding, which effectively improves our per share metrics by this amount. Additionally, we currently have approximately $250 million remaining under this repurchase program.

And now I'll turn it over to Craig.

Craig J. McPherson

Okay. Thank you, Mark. Let's start by reviewing our tertiary business, which we finished strong in 2012. Tertiary oil production was 37,550 barrels per day during the fourth quarter, an increase of 8% over third quarter levels. On a full year basis, 2012 tertiary production was 14% higher than full year 2011.

There were several key fields that had material impact on our record level of tertiary production in the fourth quarter. We'll start with Delhi. Delhi's production was up 37% from third quarter levels as we saw strong production response for the newest phase of that field. We expect production growth throughout 2013 at Delhi, until the reversionary interest is reached in the second half of the year. At that point, our net revenue interest will decrease from 76% to 57%.

As we previously outlined in our Analyst Day presentation, we expect this to reduce production in the range of 1,000 to 1,500 barrels per day, when the reversion becomes effective. At Hastings, production increased 22% from prior quarter levels, as the field responded favorably to additional compression added in the quarter. We anticipate additional growth of Hastings in 2013.

Oyster Bayou continues to show strong results, increasing 19% from prior quarter levels. We anticipate continued growth in Oyster Bayou in 2013 as that field dewaters and more wells respond to CO2.

Heidelberg's production increased 6% from prior quarter levels as we continue to see positive response from our new wells in the Christmas zone. Also, we're very pleased with our continued development in the Eutaw zone.

Aggregate oil production from the tertiary fields I haven't specifically discussed increased by 1% in aggregate on a sequential quarter basis. This represents good recovery from some hurricane downtime in the third quarter, as well as good results from increased reservoir management in those fields.

With the transactions we've completed or announced over the past 12 months, nearly all of our current non-tertiary production now comes from fields we plan to flood with CO2 in the future. Pressure from our non-tertiary assets, excluding production from the Bakken area assets sold during that period, increased by about 6% sequentially to 22,502 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 nearly flat with the prior quarter.

Let's move now to lease operating expenses. During the fourth quarter, operating cost for our tertiary properties averaged $22.59 per barrel. That's an improvement from the $23.50 per barrel in the third quarter. The reduction's primarily due to increased production, which more than offset the additional cost related to operating new tertiary floods at Hastings and Oyster Bayou.

Let's move now to year-end reserves. We announced on February 4 our year-end 2012 crude oil and gas reserves were 409 million barrels of oil equivalent. This excludes the estimated 42 million barrels of oil equivalent and proved reserves we will get from the pending CCA acquisition. Proved reserve additions during 2012 were 114 million barrels of oil equivalent, with roughly half of our reserve adds coming from CO2 EOR operations at Hastings and Oyster Bayou fields.

Our reserves are 80% liquids and 60% proved developed. 49% of our proved reserves are attributable to our CO2 EOR operations.

And nearly all of our reserves not currently attributed to CO2 EOR operations are in fields that have planned future CO2 EOR activities. The estimated PV-10 value of our proved reserves at December 31, 2012, was $9.9 billion, or a $0.7 billion decline from the prior year level. That decline was expected and is due to this impact of our strategic sale of properties during the year and the impact of lower oil and natural gas prices, which more than offset increases from additional tertiary reserves and acquired properties.

The year-end 2012 PV-10 value of our proved reserves attributable to our tertiary oil activities was $6.8 billion. That's a $1.1 billion or 19% increase from the prior year level. It's important to note that these year-end PV-10 values do not include the PV-10 value of the pending CCA acquisition, which is currently estimated at $1.1 billion.

So on a pro forma basis, we estimate that the CCA acquisition will increase our PV-10 Value to approximately $11 billion. Additionally, our estimated proved CO2 reserves at year-end 2012 increased 8% to 9.6 trillion cubic feet. Of these total CO2 reserves, 6.1 Tcf were in the Gulf Coast region and 3.5 Tcf were in the Rocky Mountains region. Our acquisition of roughly 1/3 of Exxon's CO2 reserves in the LaBarge Field added approximately 1.3 Tcf to our Rocky Mountain CO2 reserves.

Now let's move to a brief review of our Gulf Coast EOR CO2 supply operations. In Jackson Dome we produced approximately 1 billion cubic feet per day of CO2 during the quarter. The wells drilled during 2012 were primarily rate wells, which is why our proved reserves declined in Jackson Dome for the year.

Looking into 2013, we have 5 wells on the drilling schedule, with 2 of those being development wells and the 3 other wells could potentially add reserves. We continue to make progress on securing future CO2 supply from man-made sources, and we're proud to say we recently began receiving CO2 from Air Products out of Port Arthur, Texas, which is being used at our Hastings CO2 flood.

Our existing CO2 pipeline transportation system provides a meaningful strategic advantage in securing future anthropogenic sources of CO2 all along the Gulf Coast. Looking forward, we expect to start taking delivery of CO2 from PCS Nitrogen in the next few months.

Also, Mississippi Power's power plant, which is currently under construction, should be completed during 2014 and could provide up to 115 million cubic feet a day of CO2 to our Mississippi tertiary operations. In addition to these 2 sources, we're also discussing additional offtake agreements with sponsors at several existing or proposed facilities in the Gulf Coast region.

Let's move to our Rocky Mountain CO2 operations. We're pleased to report the construction of our first major CO2 pipeline in the Rockies was completed late last year. The initial 232-mile segment of Greencore pipeline connects the CO2 coming from ConocoPhillips' Lost Cabin processing plant to our Bell Creek Oil Field. The construction of that pipeline was on time and in the lower half of our budgeted range, with total capital cost of less than $300 million.

ConocoPhillips is running 6 to 8 weeks behind in the finalization of their facilities at Lost Cabin. They are currently commissioning their facilities, and we expect to start filling our pipeline with CO2 shortly. As a result, we're 6 to 8 weeks behind in our planned first CO2 injections into Gulf Creek, which we now expect to begin early in the second quarter. We expect to obtain additional CO2 supplies from ExxonMobil's Shute Creek facility, and we're working to secure a pipeline interconnect between the Greencore pipeline to the pipelines that transport CO2 from Shute Creek. This pipeline in fact is important because it's going to significantly reduce the cost and time to deliver CO2 from Shute Creek to our operated Bell Creek Field and the Hartzog Draw fields. It will also allow us to defer expansion of our Riley Ridge facility beyond the plant's target capacity of 200 million cubic feet a day of raw gas.

Moving on to Riley Ridge gas processing facility. We continue to expect natural gas and helium production to begin midway through this year. As a reminder, the delays we've experienced completing the Riley Ridge facility has no impact on our plans to construct a carbon dioxide sweetener facility near Riley Ridge, that will separate CO2 from the gas stream and then ultimately, we'll build a CO2 pipeline that could connect the facility to our Rocky Mountain Oil Fields later in the decade. So in conclusion, our CO2 supply and transportation operations are performing well, and we can expect to continue to meet the needs of our expanding tertiary 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 our first question from the line of Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Phil, what are you going to do for an encore in 2013? Had a good end to the year. Couple of questions here on the reversionary interest at Delhi, I know you'd mentioned this at the Analyst Meeting as being a late 2013 event. Has there been any change to that anticipated timing? And does your guidance reflect that change or reduction in your working interest?

Phil Rykhoek

Yes, our guidance does reflect it. It has perhaps moved forward just a little bit. I think we were assuming, probably actually late in the fourth quarter initially, and with the strong production response at Delhi and high oil prices are higher than we initially expected, both of those would shorten that time period.

Arun Jayaram - Crédit Suisse AG, Research Division

To perhaps the third quarter? Is that fair?

Phil Rykhoek

Perhaps third, yes.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. The second question, sounded like the modest delays at Bell Creek are just related to some third-party timing on commissioning at Lost Cabin. Is that -- anything else going on there?

Phil Rykhoek

No, that's it exactly.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay, okay. And finally, Phil or -- given the purchase of Conoco's interest, I think the original plan at CCA was to do some initial water floods this year, with the CO2 pilot 2014, with injection in 2016. Has anything changed regarding that plan of attack on the CCA?

Phil Rykhoek

No, just to correct one point. Actually, we expect injections 2017 rather than '16. But no, the overall plan doesn't change. I mean, we're going to look at the assets and we may start -- we're not sure necessarily when we'll start the flood or what area of the field will get flooded first. But the general plan, to get a pipeline to CCA by 2017 is still the same, and we're still doing work on water flooding and planning on a pilot late this year or early next year.

Operator

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

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

Just had a question, pro forma the Conoco acquisition, you guys are going to have a materially improved cash flow profile. Does that change your thinking with respect to the relative merits of stock repurchases versus dividends?

Mark C. Allen

No. I mean, we do, I mean at today's prices and pro forma with Conoco, we probably will have a little bit of extra cash flow in 2013. Of course, that moves around daily, depending on where prices are, but it's probably not enough to really consider, at least not a significant dividend. So I don't think -- I think that's still a few years off. We're going to kind of look at that. And of course, the stock repurchase, we still have $250 million authorized on that, but it would depend on where our stock is vis-à-vis oil price.

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

Okay. And then just on the units you're acquiring at CCA, are there any plans there this year?

Craig J. McPherson

Our plan is to continue to optimize the waterflood there. So it -- just consistent with what we're doing throughout the CCA.

Phil Rykhoek

Yes, we don't have a lot of -- I think we actually had, I don't know, $20 million or something, kind of in the forecast for CCA for capital, but it's just kind of minor, and it kind of rounds off. But no, we don't have big plans. We'll just get it acquired and look at it, and try to optimize the flood. Actually part of their interest too, just a reminder is, our non-op interest in parts of CCA that we already operate. So we're picking up additional interest there.

Operator

Our next question, from the line of Jason Wangler with Wunderlich Securities.

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

Just curious on, with Bell Creek, the injection's starting up, first half of this year. When do you think you'll see response in production, and I guess just kind of following on that, when will you be able to book some reserves from that?

Craig J. McPherson

Sure. We expect to see response in the third quarter.

Phil Rykhoek

And we -- well, reserves, as you know, we like to have a little bit of production history. So it's a little closer than we were initially with this delay. Before, we probably would have felt pretty confident we'd book them by year end, I think there's still a chance, but we'll have to have, probably 3 to 6 months of production to make the engineers comfortable to book the reserve. So it may cut it a little close.

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

Okay, so either year end or maybe even more so, mid-next year?

Phil Rykhoek

Yes.

Operator

We'll go to Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Just trying to get a little bit of a handle around your guidance range of 4% to 12% growth on the tertiary production. Pretty wide, so was hoping maybe you guys could point to the trigger points that result in production either heading towards the high end or the low end of guidance.

Craig J. McPherson

Well, the trigger points are the -- how the floods at Oyster Bayou and Hastings and Delhi continue to respond, as well as how the Bell Creek will respond to CO2. And -- so those are the triggers that we're looking for, as well as the base production holding up. And as we -- as the fourth quarter indicates, we're seeing positive responses in all those floods. So we think we're positioned well to deliver, and in the midpoint of that -- midpoint to that range or higher, so. But we need to see the rest of the year play out, but -- on the other side of that coin is, as was mentioned, when is the Delhi's reversionary interest, and so those are all the factors that play out.

David W. Kistler - Simmons & Company International, Research Division

Okay, appreciate those clarifications, and then, maybe jumping to the CO2 reserves at Jackson Dome. Obviously, getting this anthropogenic contract done and having that delivered over time makes your supply-demand balance a little bit more favorable. But can you kind of walk through what you'll be looking at to make sure that you have sufficient supply out of Jackson Dome to be able to prosecute your Gulf Coast injection?

Phil Rykhoek

Well, as you know, we have a -- if you look at our slide presentation, we have a kind of a layered approach to that. We have, of course, the proved reserves, and we have a risk drilling program. And as Craig mentioned, we plan to drill 5 wells there this year. A couple for rate, and 3 of which could add reserves. We have these anthropogenic that are coming on, the Air Products is already on, although expected to increase a bit, and then PCS and then, of course, next year, Mississippi Power. So -- and then, then we have another slice on there of other anthropogenic that we think are probable, but have not yet commenced construction. So we don't expect those to come on for a few years. But bottom line is, there is a whole program that we're of course closely monitoring the results of each piece, and then we actually have another several Tcf of other potential beyond what's even in -- on the slide. So we feel like we're very adequately covered. The pieces will move around a little bit, depending on timing of the anthropogenic and results from our drilling program. So I'm sure it won't be quite as we forecasted, but we think we have a pretty good cushion, and can modify, particularly our drilling program, up or down as need be.

David W. Kistler - Simmons & Company International, Research Division

Great. Appreciate that clarification, and then maybe just one more, if we think about kind of where the current stock is and upside to your net asset value, and we look at kind of maybe a transaction that took place today with Linn buying Berry, and we look at your production profile of kind of generally pretty predictable, long-term mature Enhanced Oil Recovery assets, do you guys look at either creating your own MLP or dropping assets to an MLP at some point or another?

Mark C. Allen

Well, I mean, as you know, we ultimately expect to produce free cash flow. We think that's probably about 4 years off, and to be honest, we -- an MLP is an option or a Linn-type structure is an option, but we haven't really worked quite close enough to really say on that at this point, but it's something we would definitely consider.

Operator

And we'll go to Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

It's just -- I'm not sure if you covered this. So sorry if I missed it, but what are your thoughts on doing additional share buybacks? And how much is left on the current authorization?

Phil Rykhoek

So we have, as Mark mentioned, $250 million left on the current authorization, and really, it's a little hard to answer because it all depends on where the stock goes and where oil goes, and we look at both of those. So the only real color is we said we wanted to be below our proved NAV, I guess is one criteria. But other than that, it's a little bit subjective. So we have some room. We have $250 million or less, and we'll just see what happens.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you, and any thoughts about potentially requesting an additional authorization?

Phil Rykhoek

Well, I mean we can consider that if we spend the full $250 million. I think that the goal would be is having that funded or have a way to fund it. So I think if we were to spend more than that, we'd probably, at least look at our CapEx through 2014 or something and maybe try to fund part of it with that.

Operator

We have a question from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

I apologize. My questions have all been answered.

Operator

Let's go to Hsulin Peng with Robert Baird.

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

So a few questions here. The first one's a bit more hypothetical. If you wanted to accelerate the development of your tertiary fields with the potentially additional cash flow you have, do you -- could you do that? I mean obviously, you should be able to draw the pipeline, the CO2 pipeline and all that, but is there, a slight possibility for you to accomplish, to move schedules forward?

Phil Rykhoek

Well as we've normally said, it's -- there's probably a little flexibility in there. So perhaps we could accelerate a few things and maybe move them up, but I think it's a relatively minor percent, or to put it another way, I don't think we could go twice as fast, no matter how much money you throw at it. And it's just because we have to manage the CO2 supply and we have to manage the transportation and then, of course, the field has to be able to take it and the recycle facilities have to be able to process it. So if you accelerate too much, you really hurt your returns, because you build bigger facilities that may only be used for a very brief period of time, or you start duplicating pipelines and so forth and the returns come down, even though you've accelerated production.

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

Okay, understood. And then the second question is, with the additional fields you -- that you acquired in the Rockies, can you talk about the availability and sufficiency of your CO2 for all your Rockies tertiary fields at this point?

Phil Rykhoek

Sure. Actually we're kind of long CO2 in the Rockies, and it's really anchored, of course, by our Riley Ridge property that we own. The current sources, the first one, of course, is Conoco at Lost Cabin, that's going to be nearly 50 million a day. That one's of course, the one that's about to start going into our pipeline. But we also, of course, did the deal with ExxonMobil. So that's up to 115 million a day. We have a contract with DKRW, the anthropogenic source, that's the plant that's not yet commenced construction, but it's still planned. That's 100 million a day initially, with plans to expand it to twice that. But all those are the kind of the auxiliary sources, and Riley Ridge is the backbone. We plan to start Riley Ridge production this year, although we don't -- probably won't take CO2 from Riley Ridge until about 2017 when the pipeline gets there. But Riley Ridge could be expanded to kind of whatever size we need. Now takes a little time and of course, takes a little money, but it's producing from the same formation that Exxon's producing from, which is estimated to have 100 Tcf of CO2. So that's the backbone of our whole play up there.

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

Great. And then last question is, have you guys thought about hedging to Brent rather than just NYMEX? Any pros and cons you think about that?

Mark C. Allen

Yes, Hsulin, we have looked at that and typically, when we have, we found it different. So it goes away pretty quickly. So we've looked at it for a couple of years, and so we're happy we actually didn't do it, because we enjoy the advantage today. So we're just being opportunistic. We don't know where it's going to go for sure. So we continue to employ our existing strategy for the time being.

Operator

And we have a question from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Actually, all my questions have been answered.

Operator

[Operator Instructions] And we'll go to Noel Parks with Ladenburg Thalmann.

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

Just a couple of things. I wanted to ask about the anthropogenic CO2. For the plants that are further out in time, you talked about some that are still planned for construction, but haven't started yet. Have you seen any shuffling in the last few months as far as any of them looking more likely or -- to happen sooner or falling back?

Phil Rykhoek

No real change recently. I mean, we put the -- we first put that kind of new slide out, I guess, at the Analyst Meeting in November, and I don't think we've seen any changes since then. So we would still kind of stick with our current forecast.

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

Okay, great. And with Port Arthur, since that's the first source that you now have online, how has the deliverability been out of that plant? I know that was a concern and a reason for keeping Jackson Dome as sort of the backbone of the Gulf infrastructure. So is the notion that some of these plants might not be as 24/7 as you would like?

Phil Rykhoek

No, it's been good now that it's producing probably about 25 million a day currently, but I mean it was planned, and there is a planned increase to double that. So it's pretty much on track, it's doing well.

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

Great, and just wanted to follow up on -- at Hastings. I remember at the Analyst Day, you talked about the compression. You gave the compression capacity to be brought online, and I think it was mentioned earlier in the comments that the field has responded well to that. Just looking ahead, what are sort of -- are there any other sort of potential bottlenecks on the way, as the field keeps ramping up this year, either on the compression side or sort of any other infield equipment or infrastructure?

Craig J. McPherson

No, no, we don't see any bottlenecks. What's going to drive the production response in 2013 is additional patterns that will respond. So the facility, we've got facilities. We're upgrading them a bit, but that's on track to coincide with the increase that we'll get as these additional patterns respond. So but we think we're on track with that.

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

Okay, I mean, I guess just give me some perspective. Is there much in the budget specifically for facility expansion on existing floods for this year? Or are you pretty much set for the foreseeable future?

Phil Rykhoek

Well, I mean there is -- there are planned expansions everywhere. I mean, there's probably in rough numbers $500 million being spent at the oil fields, and a lot of that is for facilities. Some of it are expansions. I think there is -- isn't there another compressor upgrade at Hastings? [indiscernible] So as the field grows, we continue to expand the facilities but, yes, they're all planned. In fact, the equipment, in a lot of cases, has been ordered for some time, so.

Craig J. McPherson

Yes.

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

Okay, great. So when is that compression upgrade due at Hastings?

Craig J. McPherson

I think it's the mid-year, but that's -- I'm going a bit off memory the -- on switch and all.

Phil Rykhoek

Well I -- yes, I had the same thought. So it's -- we'll stick with mid-year, then.

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

Okay, just trying to think about that more as it's going to -- as Hastings is going to assume an increasingly -- turn a big profile in the Gulf Coast for your production.

Operator

We have a question from Tim Rezvan with Sterne Agee.

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

I had a couple of quick ones for you. First, can you give any color on the timing and volumes of nat gas and helium out of Riley Ridge this year?

Phil Rykhoek

Yes. The plant capacity, initially, is 100 million a day of raw gas. About 19% of that's expected to be methane and then, of course, you'd have about 20% royalty. So I'm actually giving the numbers as I calculate it, because I can't tell you off the top of my head. So that's about 15 million a day. Now I caution you though, I think, it may take us several months to get above that -- this is a new plant, and serial #1, if you will, so I think we've probably assumed in our forecast probably about half that, assuming we kind of operate at about 50% capacity. But, ultimately, we'll get up to about 15 million a day with the first phase of the plant, and then in a couple of years we need to drill a few more wells, 2 or 3 more wells, and also expand the capacity, which is fairly easy, but we'll double that, probably the next 2 or 3 years. Helium part of it is a very small part of the production stream. It's somewhere probably around 0.5% but then, of course, helium is a big part of the revenue stream, so.

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

Okay. That's helpful. And then, lastly, can you just remind us what your WTI and LLS price assumptions are, in your '13 guidance?

Mark C. Allen

We did not assume as a positive of differentials we received today, we basically kind of built in, in most cases kind of the forward strip at any given point in time. So I mean, I think it goes down to, I guess, low teens to single digits here throughout the year. So it's probably in the, I would say $6 to $10, $6 range or so somewhere in there.

Phil Rykhoek

There's a big debate, most people think this LLS/WTI difference is going to converge, and I don't know. It seems to me, most people on Wall Street think it's going to happen in '13, some debate rather it goes into '14, but we've, in essence, built that in, so I don't think we're too aggressive on our forecast, and we still expect to be able to cover CapEx with cash flow, or have a little extra.

Operator

We have a question from Andrew Coleman with Raymond James.

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

Had a question on your CO2 supply as well, probably for the soup du jour today. You all talked about in the past, using I guess, Riley Ridge, Jackson Dome, as to how I -- your CO2 storage facilities, should you have any planned offsets in the system. I guess now, of course, you're only getting a little bit of non-manmade CO2, but what sort of volume levels do you think that you start to have to think about testing that optionality, should you have any infrastructure bottlenecks or downtime to the system as you ramp all that up?

Phil Rykhoek

Well, if I understand your question, I mean, I think it's highly unlikely Jackson Dome ever becomes a storage facility. I think that the production could be increased or decreased as need be, to accommodate anthropogenic sources, but keep in mind, we're producing 1 to 1.1 BCF a day out of Jackson Dome today. So it takes quite a few sources to replace that, and also keep in mind that we plan to use more in the future because we have several new floods coming on. So I think the forecasted demands like 1.4 or 1.5 BCF a day in the Gulf Coast, with the existing floods that we own, or I mean, the current properties that we own. So you have an increasing demand. So you put all those numbers together, I think it's highly unlikely Jackson Dome ever becomes a storage facility. We have -- you are correct, we have said that could happen long term, but I think it's many, many years away if they -- if ever.

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

Okay, sure, and I'm not saying that's going to -- you're absolutely going to be always injecting, but in terms of, kind of, one offer a day here and there if you have to start shutting things in because of the capacity issues or compression issues elsewhere, so.

Operator

Thank you, and I'll turn it back to Jack Collins for any closing remarks.

Jack T. Collins

Okay. Thank you, Lori, and thanks again to all of you for attending and participating on today's call. Before you go, let me update you quickly on management upcoming investor presentations. Mark will be presenting at the JPMorgan high-yield conference in Miami next week, followed by the Simmons Energy Conference in Las Vegas. Phil will be presenting at the Raymond James conference in Orlando the first week of March and then followed by the Howard Weil Conference in New Orleans a few weeks later. The slides for the presentation and webcast will be accessible through the Investor Relations section of our website. And if you're attending any of these conferences, we do hope to see you there. Lastly, if you mark your calendars, we currently plan to report first quarter 2013 results on Thursday, May 2, and hold our conference call that day at 10 a.m. Central. Thanks again for joining us today, and we look forward to keeping you updated on our progress.

Operator

Thank you, ladies and gentlemen. This concludes our conference call. Thank you for using AT&T Executive Teleconference. You may disconnect.

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