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Denbury Resources (NYSE:DNR)

Q4 2011 Earnings Call

February 23, 2012 11:00 am ET

Executives

Jack T. Collins - Executive Director of Investor Relations

Phil Rykhoek - Chief Executive Officer, President, Director and Member of Investment Committee

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

Craig John Kenneth McPherson - Senior Vice President of Production Operations

Robert L. Cornelius - Senior Vice President of Co(2) Operations and Member of Investment Committee

Analysts

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

Jeffrey W. Robertson - Barclays Capital, Research Division

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

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

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

Operator

Good day, ladies and gentlemen, and welcome to the Denbury Resources Fourth Quarter and Year-End 2011 Earnings Conference Call. My name is Mary, 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, Mr. Jack Collins, Denbury's Executive Director of Investor Relations. Please proceed, sir.

Jack T. Collins

Thank you, Mary. Good morning, everyone, and thank you for joining us on our fourth quarter and year-end 2011 conference call. With me today are Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; Craig McPherson, our Senior Vice President of Production Operations; and Bob Cornelius, our Senior Vice President of CO2 Operations.

In a moment, I will turn the call over to Phil and the other members of our senior management team to discuss our results. But before that, 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. 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 press release, all of which are posted to our website at www.denbury.com.

In addition, over the course of today's call, we will reference certain non-GAAP measures. Reconciliations and disclosures on these measures is provided in today's press release.

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

Phil Rykhoek

Thanks, Jack. First of all, let me just say welcome, Jack, to Denbury. I think this is his first call, but he's been with us for a couple of months. We're happy to have him on board, and he's heading up our Investor Relations. So welcome aboard, Jack.

I'm excited about the bottom line results as again, this quarter we were at record levels. This is the third consecutive quarter that we've set records in adjusted income and adjusted cash flow. Adjusted net income was $175 million, adjusted cash flow of $387 million, and that's up 18% and 8% respectively from last quarter's records. Of course, these are non-GAAP measures so do take care and note the reconciling items, which are mainly noncash and nonrecurring items.

Part of our positive results were due to our best-ever oil differentials with our net received oil price averaging $9.14 above NYMEX, at nearly $2 better than last quarter and more than $13 a barrel higher than a year ago, primarily driven by the expanding WTI-LLS differentials.

As you also probably know, because I'm sure you watch the market, the LLS differentials have been rather volatile contracting by more than half by the end of 2011 but then have begun to expand again recently. Of course, the Bakken differentials have also experienced some significant volatility. Mark will talk a little bit more about this in his comments but suffice it to say, we believe our exposure to LLS pricing will continue to benefit our overall oil price realization as we now have more than 70% of our crude sold on some basis other than WTI.

Our production growth this quarter was in line or exceeded expectations and the outlook is favorable. Craig will talk a bit more about that. Operating cost declined quarter-to-quarter, and so all of this contributes to a bottom line that significantly beat first call expectations.

A few weeks ago, we released our proved reserves, and Craig will hit the high points, but one number I always like to point out is that our proved PV-10 at year end was $10.6 billion. If you subtract our net debt, divide it into our expenditures, you'll see our proved net asset value per share is in excess of $20 per share. So what that means is if you buy the stock at today's price, you effectively get the 800 million barrels of unbooked potential that we have associated with our future EOR floods and the Bakken development for free. So while our stock has performed well in the last few months, we believe it still remains a bargain on a 3P net asset value base.

On this call, we'll give you many details about Q4 and brief in historical results, and I think you'll like all these numbers, but to me, the more important thing is the takeaway from this call, we are starting 2012 on a positive note, with both Oyster Bayou and Hastings coming on a couple of weeks early with good initial production rates. We've had good weather in North Dakota, that translates into positive production trends in the Bakken. So all that adds up to running a little ahead of schedule on our 2012 production goals.

Now while 1.5 months does not make a year is obviously we're very, very happy to get off to a great start. Further, with the asset sales we have aimed to have completed and with oil prices currently running higher than initially forecasted, our capital resources are looking strong, and we are contemplating an increase to our 2012 capital budget.

If we do so, I've mentioned this before, one of the potential additions would be the retention of a fourth operated rig in the Bakken, which would boost our 2012 production growth slightly. Other potential capital budget increases would impact 2012 production or would be intended to get a head start on our 2013 EOR program.

We're going to discuss this more internally but -- before we make a final decision but initial indications are it's looking positive. So with that introduction, let's look more of the details, and let's start with Mark's review of the numbers.

Mark C. Allen

Thanks, Phil. As Phil mentioned, we achieved record quarterly levels of adjusted net income and adjusted cash flows in the fourth quarter. In my comments, I'll provide further analysis of our quarterly results, primarily focusing on the sequential change in results from the third quarter to the fourth quarter of 2011. I would also provide some forward-looking information for your financial models.

As reported in our press release, our adjusted net income for the fourth quarter was $175 million or $0.45 per diluted share, a new quarterly record. This was up 18% from our prior record of $148 million or $0.37 per share in Q3. Adjusted net income excludes an after-tax fair value hedging loss of $104 million, primarily due to the increasing NYMEX oil prices, $5 million after-tax for CO2 exploration expense and an after-tax loss of $14 million on asset impairment charges.

The asset impairment charges related to the Vanguard units we sold in January 2012 and the balance related to a potential CO2 project that we determined was uneconomic. Our adjusted cash flow from operation, which excludes working capital changes, increased to $387 million for Q4, up from $358 million last quarter, another new quarterly record.

Our total production for this quarter was 67,234 barrels of oil equivalent per day, up 1% from the third quarter. Our tertiary production averaged 31,144 barrels per day, up slightly from Q3 tertiary production, and our Bakken production averaged 11,743 BOE per day, up 18% from Q3.

Craig and Bob will go into more detail on our production results in their comments but as stated in our press release, we have left our production guidance unchanged. Note however, that our guidance includes approximately 1,400 barrels of oil equivalent per day from the non-core properties we expect to sell this quarter, so production guidance will decrease accordingly when this occurs.

Our average realized oil price, excluding derivative settlements, was around $103 per barrel, up from about $97 per barrel in Q3. As Phil mentioned, our NYMEX WTI oil price differential continued its positive trend, increasing to $9.14 per barrel above NYMEX this quarter as compared to a $7.25 per barrel premium in Q3.

For our tertiary oil production, most of which is sold on LLS base indexes, the average NYMEX price premium was $19.44 this quarter as compared to a $14.84 premium in Q3, with some of our tertiary production receiving premiums to NYMEX of nearly $25 for the quarter. However, the LLS to NYMEX premium contracted significantly in the second half of the fourth quarter, ending the quarter at less than $10 above NYMEX but recently increasing to the mid-teens.

Differentials in our Rocky Mountain properties widened up in the fourth quarter with our Bakken production averaging an $8.42 discount to NYMEX as compared to a $5.62 discount to NYMEX in Q3. Due to a combination of strong supply growth coupled with lower seasonal demand, Bakken differentials have recently widened significantly. As a result, we expect to see oil prices for our Bakken production at significantly reduced levels in Q1 '12 potentially $18 to $20 below NYMEX. We believe the Bakken differentials should return to levels in a low double digits as seasonal demand improves and new takeaway capacity comes online.

Based on the fluctuations we're seeing in our differentials, we currently anticipate our overall corporate differential will be -- will return to more normal historical levels of a moderate discount to NYMEX in Q1 '12.

Moving on to our hedging activity. We continue to execute a strategy of protecting our oil price downside while retaining upside through cost with collars. We generally seek to protect the property at 75% to 85% of our anticipated oil production on a rolling quarterly basis, looking at approximately 6 quarters. Since our last call, we have added it significantly to our 2013 hedge positions. For 2013, we have now hedged a significant portion of our anticipated oil production for the first 3 quarters, the collars that have a full price of $70 per barrel for Q1 and $75 per barrel for Q2 and Q3 and weighted average caps of around $110 per barrel for Q1, $117 per barrel for Q2 and $121 per barrel for Q3.

In the fourth quarter, we paid approximately $1 million on our oil hedge settlements while we received about $8 million from our gas hedges. It is important to note that we have 44,000 barrels per day hedged in the first quarter of 2012, with the ceiling price of between $100 and $105, which means that based on current price levels, we would be exposed to some level of cash loss in our oil hedging contracts in Q1.

Before I begin my discussion of operating cost, please note that in the fourth quarter, we adjusted our presentation of certain taxes that have previously been included in various expense categories into a single category called Taxes Other Than Income. A description of the reclassification is provided in today's press release, and a summary of the reclassified quarterly numbers for 2011 is provided in the updated corporate presentation we've posted to our website this morning.

We believe our revised presentation is more consistent with industry standards and provides investors better clarity in our underlying operating performance. All comparisons I give today are to the third quarter reclassified numbers.

Our lease operating expense per barrel of oil saw a decline by 7% from Q3, averaging $23.08 this quarter. For our tertiary operations, this number averaged $23.59 for the quarter, down 5% from Q3. Looking forward to 2012, we expect our total company LOE per BOE to be in the mid-to-low $20 -- $20 to $25 range per BOE, with LOE per BOE starting out higher and decreasing throughout the year as production increases.

Our CO2 discovery and operating expenses increased about $8 million from Q3. The driver here was about $7 million of CO2 exploration cost we incurred in Q4, which was below the $9 million to $12 million guidance we gave on last quarter's call. As a reminder under accounting rules, we are required to expense drilling cost as we incur them on CO2 exploration wells that don't have proved or probable reserves. Drilling continued on the well in the first quarter and as a result, we expect CO2 exploration cost of between $5 million and $10 million in Q1.

G&A expenses were slightly higher from Q3 at about $28 million in Q4. This category came in lower than the guidance we provided on last quarter's conference call due to lower employee bonuses and stock-based compensation expense and higher capitalized G&A. Stock-based compensation expense for the quarter was about $6 million.

For 2012, we expect our G&A expense to be in the range of $35 million to $40 million per quarter, but generally higher in the first quarter due to incremental payroll burdens associated with divesting of long-term incentives. In the first quarter of 2011, our G&A expense is around $42 million. We anticipate the stock-based compensation expense to range between $7 million and $9 million per quarter in 2012.

Our overall DD&A per BOE increased to $17.80 this quarter, as compared to $16.59 in Q3. The increase was primarily due to upward revisions and estimated future development costs for our proved undeveloped Bakken reserves. We anticipate that our DD&A per BOE will continue to increase moderately in the first part of 2012, but we do expect some offset in our overall rate from anticipated reserve bookings at Oyster Bayou and Hastings Field later in the year.

Our taxes other than income on a per BOE basis increased to $6.34 this quarter as compared to $5.88 in Q3 as higher oil prices drove our severance taxes higher. Our severance tax rate as a percentage of our oil and natural gas revenue remained steady at approximately 5.5%. This category will continue to fluctuate with commodity prices.

Our effective income tax rate for the quarter of 34% was less than our 38% statutory rate as differences between our 2010 provision and filed tax returns impacted the current quarter. For 2012, we anticipate that our tax rate will be between 38% and 39%, slightly higher than our statutory rate with current taxes representing about 25% to 30% of our total taxes.

For Q1 '12, we estimate that current taxes will be significantly higher due to the sale of our Vanguard units, which had no tax basis and the expected sale of oil and gas properties. These sales are estimated to provide approximately $240 million of proceeds, and we project current taxes related to these sales could approximate $40 million. As a result, we estimate that current taxes could be as high as 70% to 80% of our total taxes in Q1.

Moving on to our capital structure. Average debt outstanding was $2.6 billion as compared to $2.4 billion in Q3, with increase due primarily to higher bank debt associated with share repurchases. Interest expense, net of capitalized interest, decreased sequentially to $35.7 million from $37.6 million last quarter. Higher capitalized interest more than offset the increased interest paid in our credit facility. Capitalized interest was $19.6 million as compared to $17.9 million in Q3. We currently expect our capitalized interest to be between $12 million and $18 million per quarter in 2012.

We had $385 million outstanding on our $1.6 billion bank facility at the end of the quarter, up from $110 million at the end of Q3. As of the end of January, our bank borrowings were $500 million and net borrowings were $315 million after considering our cash on hand. Our capitalization metrics continue to be very strong, with our debt-to-capital ratio at approximately 36% and our debt to Q4 annualized adjusted cash flow and EBITDA at 1.7x and 1.6x respectively.

During the fourth quarter, we spent $195 million to repurchase approximately 14 million shares of our common stock or 3.5% on those shares outstanding at September 30, 2011, at an average price of less than $14 per share. While we are authorized to purchase up the $500 million under this program, we have not purchased any stock since year end. We will continue to look for opportunities to purchase our stock if it trades at a meaningful discount to our proved net asset value.

For 2012, our capital budget remains at $1.35 billion, which excludes estimated expenditures for capitalized interest in tertiary start-up costs and assumes approximately $75 million in estimated expenditures financed with sale-leaseback transactions.

We presented our expected sources and uses of capital for 2012 at our Analyst Meeting last November. There are basically 4 components to this analysis: cash flow from operations, asset sales, capital expenditures and stock repurchases.

Although we have seen our positive oil differentials contract from when we put the analysis together, with oil prices above $100 and with a good start to our 2012 production, our cash flow is starting out ahead of forecast. We expect to have sold assets of nearly $240 million by the end of February, already ahead of our midpoint with one more small property sale expected later this year. Our stock repurchases have slowed down as discussed above, which potentially leaves us with more capital available. In light of this, we are reviewing the possibility of increasing our 2012 capital program.

And now, I'll turn it over to Craig.

Craig John Kenneth McPherson

Okay. Thanks, Mark. I'm going to provide an overview of our production operations from the last quarter, and I'll start with our tertiary operations. Tertiary production averaged 31,144 barrels of oil per day during the fourth quarter, which is essentially flat compared to tertiary production in the third quarter of 2011. I'm going to highlight several key fields that had material production impact or that reached key milestones. And we'll start with Heidelberg. Heidelberg tertiary production increased by approximately 590 barrels of oil per day compared to the third quarter, and most of that increase came from new patterns in the East Heidelberg area. We conducted extensive conformance work in the West Heidelberg Field during the third and fourth quarters to the redirect CO2 into zones previously not injected into. We're very pleased with the results and production has now stabilized at West Heidelberg. We continue to monitor this field closely with regular surveys of our injection and our producing wells.

Moving to Tinsley. Tinsley saw a production decline by approximately 740 barrels per day compared to the third quarter, and this is much as we had expected. This is much as we had expected. This decline was due to the reduction of CO2 injection and reducing the pressure in parts of the field to address the old wells that were improperly plugged and abandoned by prior operators.

Just a reminder of what happened in the third quarter. As we were expanding the CO2 flood into new patterns in the southeastern portion of Tinsley Field, we found that multiple old wells, many dating back to the '40s and '50s, had been improperly plugged and abandoned by prior operators. These old wells, which have been reported as having been plugged and abandoned by the previous operators did not have sufficient cement in the old well bores.

Without the cement plugs in place, we are unable to confine the CO2 injection into the specific target zone. As a result, we had to stop injecting CO2 in the several patterns, reduced the reservoir pressure and work over 29 wells to properly plug them. Our current status is we have resumed CO2 injection in all of the impacted areas, and we're finishing up the last 2 wells. We're pleased to say that reservoir pressure is building and production has turned the corner and already begun to increase.

Delhi Field. Delhi Field continues to enjoy a nice production increase for the reservoir response to CO2 injection, and we put more wells online. Production increased by 420 barrels per day compared to the third quarter. We continue to be very pleased with Delhi's response and expansion of the field continues.

At Oyster Bayou, we reached the significant milestone on December 14, 2011, when the field started production, and this represents us being 2 weeks ahead of schedule. We're encouraged with the early reservoir response, and we anticipate additional production as the well is dewatered.

Adding to a significant milestone is the Hastings Field. Hastings Field started production on January 13, 2012, which is also a few weeks ahead of schedule. So while the Hastings Field did not have an impact on our fourth quarter 2011 results, it's a very important part of our future. Currently at Hastings, we're producing from 10 wells, and we anticipate opening up more wells in the second quarter. Hastings is also starting off very well.

The start of the Hastings and Oyster Bayou fields culminates 5 years of planning and development, which includes the construction of a 325-mile pipeline to transport and inject CO2 from our natural source near Jackson, Mississippi. We expect to book proved reserves in both of these fields in 2012, with Oyster Bayou likely in the first half of the year and Hastings in the second half.

Moving on to lease operating expense. Our operating cost for our tertiary properties averaged $23.59 per barrel in the fourth quarter, which is a 5% reduction compared to $24.91 per barrel in the prior quarter. We reduced our tertiary operating cost by approximately $4 million from the third quarter. This decrease is primarily driven by lower workover cost and a reduction in certain annual maintenance expenses, which occurred in the third quarter.

Non-tertiary operating cost were down by $1.80 per BOE compared to the third quarter of 2011. Our total company lease operating cost on a unit basis for the fourth quarter was $20.08 per barrel. With that, let's talk just a bit about our 2012 production forecast.

Our outlook for the full year 2012 production is unchanged from the guidance provided at our Fall Analyst Meeting. However, as we announced in mid-January, we have agreed to sell certain non-core properties in Mississippi and Louisiana for $155 million. Our guidance included 1,400 barrels a day from these fields that will be sold.

We're off to a very good start in 2012 with Oyster Bayou and Hastings online. Oil production from both fields is currently exceeding our expectations. We look forward to production increasing through the year as these new fields join the continuing development of Delhi, Tinsley and Heidelberg fields in drilling our tertiary production. Bob is going to talk about our strong Bakken performance in his comments in just a moment.

Moving on to our year-end reserves. As we announced on February 6, our year-end 2011 proved oil and gas reserves were 462 million barrels of oil equivalent. Our reserves increased by approximately 64 million barrels compared to the previous year, and that represents a 367% replacement of 2011 production. Reserve growth was driven by Bakken drilling activity and our Riley Ridge acquisition.

Our reserves in production are very heavily weighted towards oil. 77% of our reserves attributed to oil. Looking forward to 2012, we anticipate reserve additions from the new fields Oyster Bayou, Hastings, and from the continuing Bakken drilling program.

With that, I'll turn it over to Bob.

Robert L. Cornelius

Thank you, Craig. In my comments, I'll cover our fourth quarter Bakken activity, the Riley Ridge facility and then report on the major pipelines and CO2 supply projects. Improved completion activity in the Bakken continued during the fourth quarter as we were able to complete 10 wells during the period. The completion activity resulted in improved production rates, additional proved reserves during the fourth quarter and in our Bakken production. Our Bakken team continues to introduce improvements to the drilling and completion process, as well as overall well operation.

In fact, Bakken production rates increased 18% over the third quarter rates averaging 11,743 BOEs per day during the fourth quarter. A full summary of our recent Bakken well results, including the IPs along with 30-, 60- and 90-day average rates are available on our corporate presentation posted to the Investor Relations section on our website.

I think one important point to note in this detail is that many of our wells completed during the fourth quarter had 60- and 90-day production averages that were greater or better than the initial 30-day averages. Now this indicates that our wells have good sustaining production rates and also illustrates that sometimes we are not able to produce a well with the maximum initial flow rates often due to stock tank shortage or transportation capacity constraints. This also demonstrates the drawback of putting undue emphasis on the initial published short-term production rates.

We currently have 5 operated rigs in the Bakken, and we plan to reduce this rig count to 4 when 1 of the rigs we have is allowed to expire or when its drilling contract expires. We are on track to have all significant lease hold positions held by production during the second quarter. Once leases are held, we will be able to shift on multi-well or pad drilling. We'll be able to better utilize our walking rigs in this field.

Our walking rig inventory includes 3 efficient flex drilling rigs. With these new drilling rigs in the multi-well drilling pads, our goal is to continue to shave off the number of days it takes to drill a well and then make rig moves. We recently drilled in quarter 3 Three Forks zones. There was 2 in the Cherry and 1 in Murphy Creek. We have not completed the wells but initial evaluation of the cores indicates positive results. Our plans are to drill approximately 17 Three Forks wells during 2012.

Moving to Riley Ridge and LaBarge Field located in Sublette County, Wyoming. Strategically, Riley Ridge unit will provide us with approximately 417 net Bcf natural gas, 12 Bcf of helium and probably more importantly, approximately 2.2 Tcf of CO2, that's to our interest.

There's an additional helium, methane and CO2 potential in the adjoining acreage, as we also have a working interest in those acres. Our operating team is completing construction and regaining the commissioning of the various plant systems. The producing wells that will feed this plant -- have been completed and the product sales and pipelines have also been commissioned. The process of natural gas and helium from Riley Ridge Field is expected to begin in the middle of the second quarter of 2012. This is a little later than we initially expected due to modest delays and final completion of the plant.

With the construction of an additional processing facility to separate the CO2 from the remaining gas stream and the construction of a CO2 pipeline to our EOR field is expected to be completed approximately 5 years. For the most part, much of this expense is processed in the CO2 will carry the sale -- the processing of CO2 will be carried by the sale of helium and methane.

A quick update of the Greencore pipeline, our first CO2 pipeline in the Rocky Mountains. The pipeline -- this pipeline will connect ConocoPhillips' operated Lost Cabin facility to our Bell Creek Field that's approximately 150 miles in a 20-inch diameter, 232 mile Greencore Pipeline was completed during the fourth quarter of this year. 2012 construction activity to resume during August after wildlife stipulations are lifted. This final segment should be completely commissioned by December of this year. Compression and meter equipment at the Lost Cabin facilities are also in order and should be ready for operations at year end.

Now moving south to Jackson Dome area, where our CO2 production rates averaged over 1 Bcf per day during the quarter. During the fourth quarter, we had 2 drilling rigs working in the Jackson Dome area, 1 rig is drilling a development well in the Gluckstadt Field. This well will be completed some time during the second quarter of 2012, and that will allow us to the increase our CO2 production rates to our EOR fields.

The second well is an exploratory well on a separate geological structure. Drilling operations are completed and it appears that the well is not productive. This well was testing a portion of reserves we categories -- categorized as possible reserves at our Jackson Dome area. Our future plans in the Jackson Dome area are to continue to drill the many development opportunities in the area. Our geological team has identified 18 different drilling opportunities in Jackson Dome area. These locations will be hydrated and drilled to maintain our CO2 production rate above 1 Bcf a day. We still believe there are several -- we still have several Tcfs of unproved potential with Jackson Dome, which could find us CO2 for future oilfield acquisitions. We also continue to pursue various man-made CO2 operations in our Gulf Coast properties. Our extensive CO2 flooding activity and the pipeline infrastructure in the region provide us a meaningful strategic advantage to capture man-made CO2.

Mississippi Power plant in Kemper County is on schedule to be completed during 2014 and it should deliver approximately 115 million cubic feet a day or more of CO2 to Southeast Mississippi. Air products Port Arthur gasifier is expected to be online about a year from now, the first quarter of 2013, and will provide approximately 15 million cubic feet to our Hastings Field.

Also we've seen with the improved economic conditions and a healthier capital markets and the EPA recognizing CO2 EOR as the potential solution to carbon sequestration. We have seen an uptick in a number of discussions we are having with potential CO2 purchasers on how we might help them take their CO2 into our pipeline systems.

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

Jack T. Collins

Okay. Thank you, Bob. Mary, that concludes management's prepared remarks. Can you please open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Hsulin Peng with Robert Baird.

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

This is Hsulin. So my questions are regarding Oyster Bayou. I was wondering, can you give more color on the specific production rates? And I know you mentioned it's exceeding your expectation, and also how you expect that to trend in 2012?

Phil Rykhoek

Well, we've avoided as you can see in all of our conferences about giving specific rate other than to say we're enthused about the results, and we're trending ahead of forecast. As to expectations, you can kind of extrapolate based on the chart that we have in our presentation that shows where Oyster Bayou is expected to go. We expect it to peak something less than 5,000 and peak in 12 to 18 months. So you can kind of extrapolate from that what we expect in 2012. But we started the -- production started about 2 weeks early and is running a little bit ahead of forecast. So we are hesitant to give out numbers because we just don't think that 45 days into the year necessarily denotes a trend.

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

Okay. No, that's fair. So are you anticipating to give us more details at a later date like maybe second quarter or a separate press release?

Phil Rykhoek

We'll give you some update definitely at the first quarter earnings which is in what, early May.

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

Okay, got it. And also just on your 2012 production guidance, is it -- given the early production success, is it fair for us to think about the production guidance being in the upper half of the guidance, or is that too early to say?

Phil Rykhoek

Well I guess, yes, if we can take this 45 days and duplicate it to the rest of the year, since we're a little bit ahead of forecast, that would kind of assume midpoint. So yes, today we're above midpoint.

Operator

Our next question comes from the line of Scott Hanold with RBC.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So the LLS premium worked out nicely. Can you go through some of the numbers? I missed them. How much of your production rate now are you selling in the LLS? And are you capable of locking in some of that premium when you can, or is it basically just front month sort of pricing contracting that you're doing?

Phil Rykhoek

I believe it's around 45% now is sold on LLS. There's about another 25% that's sold on other indexes different from WTI, generally better than WTI, and that's why we kind of said that 70% or so was something on the non-WTI basis. So we've gradually -- we improved that just a little bit from what -- from the numbers we used to give. To the second part of your question, I mean yes, you can lock in spreads. We haven't historically because we've always thought they were a little conservative, but the thing keeps moving around quite a bit. So I don't know. I guess that's always an option. We've always been doing our hedges just on WTI. We will see. LLS is back out what, 15 to 20 again, so we'll see what happens.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So that -- into that first question, so that 70% it's 45% to LLS and 25% to others. And then is that like Maya [ph] and other stuff like that?

Phil Rykhoek

Yes.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And the next question is on the Bakken rig count. So right now you're at 5, you're going to drop down to 4, and then I guess that goes down to 3 as well. And then you're going to have to put 3 walking rigs and you could add a fourth. Is that -- am I understanding the progression on that one potentially correctly there?

Phil Rykhoek

Yes. I mean, the numbers that are in the budget assumes that we go to 3 by midyear. What we're kind of saying is if the trend looks positive for our capital resources so it's probably more likely than not that we keep that fourth rig, even under 4.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, understood. And it seems like you've kind of now are committed to the Bakken. I mean early on, I guess when you acquired that asset, it kind of seemed like it was a little bit not unsure of kind of what the long-term plan on that asset was. But at this point in time, is this definitely something you intend to sort of keep and further develop, or it still an option always to potentially trade it or do something else?

Phil Rykhoek

I knew somebody would ask that question. I don't think the answer has changed. We've always felt like we want to maximize the value of this asset, and that's what we're doing, and we're getting good results and rates are improving, reserves are up and so forth. But it's -- it always is an option depending on future needs or what deals come up that we could use it to help pay for something else.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, fair enough. And my last question. So Oyster Bayou and Hastings, you have opportunity to book some reserves in 2012. How is that going to look? I mean typically -- I mean, how much do you expect in that first year when you get some production of that could you get on, is it like half of it or more?

Phil Rykhoek

Well, the guidance we usually give, if you kind of follow our history, the independent engineers usually give us somewhere around 75% of our 3P number when we initially book reserves. So the numbers we show on our slide show represents the 3P. So I guess if I were to forecast, I'd say you probably ought to take about 75%. I'd probably take the low end of the range, just because Hastings actually has a range. Actually, both of them do. And that would probably give you a rough idea of what we think we might book in 2012. I think if you add it up, it's probably somewhere between 50 million to maybe 60 million or 65 million barrels is kind of the range, but that's kind of how we get there.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, so you don't need to get that up to closer to the -- or ramp up by the end of the year in all the -- in both Hastings and Oyster to get that 75%. It just demonstrates it's ramping on schedule, is that kind of how that goes?

Phil Rykhoek

Yes, you kind of need to show -- well, you have to show a production response to the CO2. And the way we've kind of defined that is to response better than maybe what it was producing before. And Oyster Bayou of course came on first, so we think that one will get booked first. Hastings will probably, one, it's a bigger number; and two, it's probably going to ramp up a little bit slower so we're -- it's probably the second half of '12 before that one gets booked.

Operator

Our next question comes from the line of Jeff Robertson from Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Phil, if you will maintain a fourth rig in the Bakken, would that be a FlexRig or will you -- or will it be a regular rig?

Robert L. Cornelius

This is Bob Cornelius. It will be a regular rig, but the one we have is a walking rig. So we would be able to use the multiple pads and do that, so it will be an efficient rig.

Jeffrey W. Robertson - Barclays Capital, Research Division

And then just secondly, in terms of capital priorities, if you do decide to increase the budget at some point this year, is it most likely that those dollars would go to the Bakken? Or is there anything you all could do in any of the EOR projects to either accelerate patterns in existing fields or pull any of the other floods forward?

Craig John Kenneth McPherson

Well, certainly the Bakken is -- and certainly the capital, but -- this is Craig by the way. And we do have several fields that we could accelerate our 20 -- 13 probably into 2012. So it's been specifically Hastings, Delhi and Tinsley. So we have all good investments there that we could accelerate. It would not have a significant -- or would not have an impact on 2012 production, but it would give us a head start for 2013 production in tertiary side.

Operator

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

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

I just want to probe a little more on the potential for the reserve bookings at Delhi and Oyster Bayou. If you -- when you put that in, how much, I guess, or probably would that be on the PDP side, or would that all be on PUDs?

Phil Rykhoek

High percentage would be PUDs. I mean, the only PDP would be the wells that are currently producing and the curve associated with that.

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

Okay. And if I heard it right, it was -- you have 10 wells in Hastings right now. What was the well count in Oyster Bayou?

Craig John Kenneth McPherson

We have 19 producers currently. We're going to drill 8 more for this year, and that will be fully developed.

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

Okay. All right. Great. And then I'm thinking about, I guess ways to accelerate -- you probably -- you have $10.6 billion of PV-10, only a little over $2.5 billion of debt. You probably have room to expand that credit facility. But I imagine you'll be waiting to see kind of what the -- or I guess, what were you looking for in the next few months that would give you an indication whether you could or would decide to increase your borrowing base?

Phil Rykhoek

I don't know that we need to increase our borrowing base. I mean, the issue is we don't really think we need it. Yes, you're correct. I mean, Mark can maybe give you more color, but I know we could handle a much bigger borrowing base than we have. I don't know what the precise number is, but what we just haven't needed it and funny thing, bankers want fees when you increase it. So we haven't felt the need to pay for that.

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

Absolutely. Well I'll worry about that another day, I guess. But the last question I have then was on the -- with air products, you said -- if I heard it right, coming on first quarter of 2013 adding some CO2 for Hastings. Should we be thinking about any compatibility issues between the, I guess, Jacksonville and CO2 making its way down to Houston versus the man-made CO2 kind of mix in the reservoir?

Robert L. Cornelius

No. I mean the CO2, the compound CO2, what we do -- we have fairly tight standards on what enters the pipeline. So any of the small impurities are in the parts per million capacity, so there's no discussion of compatibility.

Operator

Our next question comes from the line of Jason Wangler from SunTrust.

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

I had a quick question and I think you may have answered it a bit, Phil, but on those Bakken rigs, the 3 that you'll keep and maybe the fourth, those are able to drill on pads currently. You won't have to switch those out?

Robert L. Cornelius

Correct. Yes, sir. We have 3 of the FlexRigs, and really they are skid type, but they can move on the pad. And then we have a Patterson rig, which we employed for -- since we've owned it from Encore, and that is a walking rig. And so what we're trying to do is as we get -- all of our acreage will be held after April, May, significant acreage, and then what we'll do is we'll start to optimize our drilling program to, A, to a better well and, B, use a skid pad to reduce our cost, and especially the moving cost related to the Bakken.

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And just one other thing, the stock repurchase looks pretty smart now obviously considerably below where the shares are today. Are you pretty comfortable just letting that be for now? Or are you're still being opportunistic as far as maybe going back and buying some shares?

Phil Rykhoek

Well I think as Mark reported, we haven't purchased any in 2012. That particular stock is trading at least near proved NAV, which is still a bargain, as I pointed out. But what we've kind of said is we'll just be opportunistic. We actually have authority to spend up to $500 million, we've spent just around $200 million. But we've kind of used our threshold that it kind of trades kind of significant. A proved NAV is kind of the threshold or the trigger. So we're there if something happens, but today we're not purchasing any.

Operator

Our next question comes from the line of Dan Guffey from Stifel.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Could you talk about exploratory plans for wells in Jackson Dome over this year and next year?

Robert L. Cornelius

Well first thing we're going to do is that we drilled the well which was not productive, so we're evaluating that. Even though that one location wasn't productive, it doesn't mean there's not a lot of other opportunities in the area for additional drilling of exploratory well. With that -- so that aside, we do have 18 additional wells in the Norfolk sand that we have identified as development-type wells, and so we have those wells that we will incorporate into our plan, which we already incorporated in plan. But we'll look at those to ensure that we have at least 1 Bcf of gas every day. There's some also zones, some intervals above the Norfolk sand, which is our primary producing sand that smack over, that we think it has a quite a few reserves. It does have some impurities in it. It's not as pure as the North Lake, but definitely can be -- the gas can be -- the CO2 can be cleaned up and added to our proved developed reserves.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. And kind of switching gears over to the Bakken. You guys mentioned you cored 2 wells in the Three Forks and the Cherry area. Just wonder if you can kind of talk about your expectations for reservoir kind of contrast to the reservoir quality with the Bakken, and then kind of give an estimate for EOR in that area.

Robert L. Cornelius

Okay. Well, actually we drilled 3. We drilled and cored 3 wells, 2 of them are in Cherry area and 1 was in the Murphy Creek area. But we -- seriously, we just got those things out about 2 weeks ago. So they're at the lab getting thin slice and all that things you do to core to the analysis, so we really don't have it. I mean to say there are geologists and the folks on the rig were very pleased with what they saw from those, and we feel like -- we said we have approximately half of our wells were going to be Three Forks wells during -- in 2012 drilling period.

Phil Rykhoek

We just haven't done -- we've been trying to hold acreage, so we've been drilling kind of slam dunk stuff and drilling Bakken wells. And we really haven't tested the Three Forks in most of our areas. So that's really something that will get more emphasis in 2012.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And I guess, once you hold all the acreage and start drilling off the pads, how much do you expect to save from completed well costs?

Robert L. Cornelius

Well, I think just on move alone, it depends on what the weather is obviously up there, if it's snow and ice versus -- and you have some load issues sometimes during the melt breakup, but we're looking anywhere between $300,000 to $400,000 per well just on the move, just by using a walking or skid rigs.

Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And you guys have 5 rigs now and you mentioned you're going to 3 or maybe 4 by midyear. Where are they at? Where are your rigs at currently, and then where do you plan on having them for the rest of the remainder of the year, focusing I mean obviously on Cherry and Murphy Creek, but are you going to kind of step out and go into Bear Creek or Camp?

Robert L. Cornelius

The answer is, right now they're in Cherry area mostly. We do have 1 in Murphy Creek. Our plans are to go out and, like I said, first of all hold all the significant acreage. And then once that gets done, we're going to slide those rigs around and use it in the most efficient place we can. So we're going probably going to drill those places that we can see Three Forks potential and increase our production, increase our reserves. So as far some of the outlying areas that we don't see as being as productive, we may drill some wells out there but not many.

Operator

Our next question comes from the line of Noel Parks with Ladenburg Thalmann.

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

Just a few things. I just missed my timing earlier on cost. What is the DD&A expectation for 2012?

Mark C. Allen

Well, we ended the fourth quarter just below $18 and we project that, that will kind gradually increase here in the first part of the year. We do expect to see some offset to that increase later in the year as we book proved reserves at Hastings and Oyster Bayou. But I would expect some moderate increase here in the first half of the year at least.

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

And I guess going back to Jackson Dome for a minute. You're talking about -- or Bob was talking about how even though the particular prospect you drilled didn't work out, that it was still possible there are other things you could do on that same structure. Could you just talk a little bit more about your evaluation process from here on? I don't know if you're able to go back and look at the seismic and make adjustments based on that, that can give you more clarity going forward.

Robert L. Cornelius

So we could -- yes, again, we can address that. And you hit it right on nail on the head, Noel. What happens is when you look at an exploration project and we use 3D seismic, you get a seismic signature and seismic looks a certain way. And once you get the well drilled, you can then look at the velocity of the rock, how quickly the sound travels through the rock and compare it to the seismic, and you can know ultimately what the seismic signature look like compared to what the actual reservoir or the rock look like in the formation. So with that information, we realized why the well was tight. It didn't have a lot of permeability. So now we think we know what happened, so we're going to go back and reevaluate the 3D seismic, take the information we've learned and go back and look at what other prospects might be out there. But I want to tell everyone too that we drill this well, but we did not put this well or anticipate this well for producing for a couple of years because of the location of the well, pipeline had to be laid. Because of the location of the well, it had to be dehydrated and processed. So really, our expansion is still in our development program is where our expansion was in Jackson Dome for the next 2 or 3 years.

Phil Rykhoek

We would probably have been a little conservative in what we've shown as probable and possible there. And as Bob said, we have like 18 wells we could drill. Some of which, have actually had a well drilled in that area before, but we still don't call it as proved. So some of it's very, very low risk, and we're still kind of with the result of this well, we're looking at everything we can and coming up with kind of a schedule of what we do. But we just feel like there's a lot of potential still there, and probably our outlook of proved or probable and possible probably really hadn't changed.

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

Great. And looking ahead to the man-made CO2 plants, Mississippi Power and air products, can you just refresh my memory? We've been talking about those being underway for so long. As far as the expense for the pipeline connection from the plant to Denbury's existing system, is that cost borne by the project or is that part of what Denbury commits to in getting the rights of the CO2?

Robert L. Cornelius

They vary. We do -- I don't want to get into our contracts, Noel, confidentiality reasons. But they vary. If the processor pays for the compression in the pipe, then obviously we have to pay a little bit more for the CO2. If Denbury captures and pays for the compression in the pipe, then we pay less. That's -- I don't want to get into the contracts, but that's how we structure it.

Operator

[Operator Instructions]

Phil Rykhoek

Okay, Mary. It sounds like there aren't any more questions. So if it's okay, we'll conclude here. I want to thank everybody for their attendance and participation. Just looking forward to let you know that Mark will be presenting at the JPMorgan High Yield Conference in Miami next week. So be aware of that. And then we have the IPAA conference coming up in New York the middle of April. I'll be presenting on April 16, and then I think we're going to do -- spend 2 or 3 days on the East Coast and try to meet with several investors during that week. So if you'd like to set up a meeting with us, please contact Jack. And then looking forward to the first quarter results. We plan to report that on Thursday, May 3. So we look forward to keeping you updated on the progress. Thank you for your attendance today.

Operator

Thank you. And ladies and gentlemen, this conference will be available for replay today after 12:30 p.m. Central Time through March 23 at midnight. You may access the AT&T teleconference replay system at any time by dialing 1 (800) 475-6701 and entering the access code 220093. International participants, dial (320) 365-3844. That concludes our conference for today. Thank you for your participation and for using AT&T executive teleconference. You may now disconnect.

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