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Executives

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

Phil Rykhoek - Chief Executive Officer and Member of Investment Committee

Robert Cornelius - Senior Vice President of Operations, Assistant Secretary and Member of Investment Committee

Ronald Evans - President, Chief Operating Officer and Member of Investment Committee

Analysts

Scott Hanold - RBC Capital Markets, LLC

Xin Liu - JP Morgan Chase & Co

Sven Del Pozzo - John S. Herold

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Nicholas Pope - JP Morgan

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Richard Tullis - Capital One Southcoast, Inc.

Scott Wilmoth - Simmons

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Eugene Lipovetsky

Noel Parks - Ladenburg Thalmann & Co. Inc.

Denbury Resources (DNR) Q4 2010 Earnings Call February 23, 2011 10:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Fourth Quarter 2010 Earnings Release Conference Call. [Operator instructions] And at this time, I will turn the conference call over to your host, Mr. Phil Rykhoek. Please go ahead, sir.

Phil Rykhoek

Good morning, everybody. Welcome to our fourth quarter earnings conference call. Since this is the last time to discuss 2010, I thought I'd maybe just highlight a few of the accomplishments we had last year. As everybody probably knows, we acquired Encore Acquisition, a $3.8 billion deal, which not only established a new core EOR area for us in the Rockies, but it's also turning out to be a highly profitable acquisition. And I might refer you to look at our slideshow. We have a slide on that. It's on our website.

Of course, to pay for it, we sold $1.5 billion of nonstrategic Encore properties to reduce that debt. These were completed ahead of schedule and obtained prices that were better than expected, and we've now restored our leverage to pre-Encore levels so we're in great shape going forward. We recently completed a four-year project, the $884 million Green Pipeline, a strategic asset that will pay dividends for us for many years to come. And as a result, we have commenced a few injections into both Oyster Bayou and Hastings Field in Southeast Texas.

Tracy will talk more about reserves, but in summary, we added two Tcf of proved CO2 reserves last year. Part of that came from an interest we acquired in Riley Ridge Unit in Southwest Wyoming, a property that contains natural gas, helium and also CO2 and H2S. And the remainder incremental from additional development of our natural resource at Jackson Dome increased and improved reserves there to slightly over 7 Tcf as of year end. We still have significant remaining potential left in that field and plan to drill a couple wells there in 2011 that may prove up some additional CO2 reserves.

On the oil and gas side, we nearly doubled our proved reserves between year end, primarily from the Encore acquisition. And it all came in at a very respectable buying cost of just under $14.25. Our biggest reserve adds, other than Encore, were the almost 30 million barrels at Delhi and about 33 million barrels in the Bakken play. And most importantly, through all this activity, we met or exceeded our production economic forecast including the fourth quarter results that we're discussing today.

Our fourth quarter production was previously announced coming in ahead of forecast and I think as you look through the financial numbers today, you won't see anything that would disappoint you as we remain on forecast in almost all measures and I believe we're slightly ahead of first call. But I'll let the other guys give you the details. With me today from Denbury, I have Tracy Evans, our President and COO; Mark Allen, our Senior Vice President and CFO; and Bob Cornelius, our SVP of Operations. And we'll start with Mark's review of the financials. Mark?

Mark Allen

Thank you, Phil. As reported in our press release, Denbury had net income for the fourth quarter of $10.4 million or $0.03 per basic common share. Our Q4 net income includes a non-cash fair value loss in our derivative contracts of $129.6 million. Our net income adjusted to exclude fair value hedging changes, Encore merger-related costs, incremental deferred taxes and income from early settlement of certain 2011 natural gas derivative contracts was $86.9 million or $0.22 per share.

As we have typically done, I'll primarily focus on the sequential results of the third and fourth quarters of 2010. During the fourth quarter of 2010, our tertiary production averaged 31,139 barrels per day, 5% higher than our Q3 tertiary productions. For the full-year 2010, our tertiary production averaged 29,062 barrels per day, 19% higher than our 2009 tertiary production. Our tertiary production guidance for 2011 remains unchanged at 32,500 barrels per day. Even though we had a great year in 2010 with 19% tertiary production growth year-over-year, well ahead of the 13% growth rate initially forecasted, we have left our 2011 production target at essentially the same place as what it was two years ago. In other words, we do not expect that higher production in one year will necessarily translate into higher production in the next. It just means we achieved our higher production rate sooner than we expected.

In fact, as Bob will discuss in more detail, 2011 tertiary production to date has started out generally flat with Q4. So while we have a month left in the first quarter as of today, we don't expect much of the quarter-to-quarter growth in Q1. Our total company production for Q4 was 76,435 BOE/d. Our production for Q4, adjusted to exclude production associated with all asset divestitures, including the sale of Haynesville and East Texas and ENP was 63,712 BOE/d. Our Bakken production averaged 5,193 BOE/d, a 12% increase over Q3. Our total company production guidance for 2011 is also unchanged at 67,400 BOE/d.

In a few minutes, Bob will provide more details about our production results. Our average oil price received including derivatives settlements was $79.18 per barrel in Q4 as compared to $71.63 per barrel in Q3. Our NYMEX oil price differential was $3.90 per barrel below NYMEX in Q4, essentially the same as the Q3 NYMEX variance of $3.86 per barrel below NYMEX. Differentials in our northern properties were negatively impacted during a portion of both the third and fourth quarters as a result of a temporary pipeline shutdown, although much of the differential is offset by higher net prices for our Gulf Coast production.

You may have noticed recently that the Light Louisiana Sweet oil price has traded at a significant premium to the WTI NYMEX oil price. Throughout most of 2010, LLS [Light Louisiana Sweet] traded at slightly positive to $5 higher than WTI. Since near the end of January 2011, LLS has traded between $10 to $20 higher than WTI. The significance of this is that roughly 40% of our oil production is marketed on an oil price that incorporates this positive LLS differential. In general, the average of this differential goes into a pricing formula that is realized in the following month.

For example, the average LLS differential in February will impact the prices we receive from March production. Therefore, we currently anticipate that our companywide NYMEX differential should be a little better in Q1 2012. However, we are not sure of how long the LLS differential will remain at these levels. Although our lease operating expenses were down approximately 1% from Q3 to Q4, our lease operating expenses on a per-BOE basis increased from $18.43 per BOE in Q3 to $18.66 per BOE in Q4. The increase on a per BOE basis was due primarily to the impact of asset sales in Q4, which were predominantly natural gas and therefore, had a lower cost per BOE.

Excluding the LOE and production associated with sold properties, our Q3 and Q4 LOE per BOE would have been approximately $20.54 per BOE in Q3 and $20.43 per BOE in Q4. I would expect our LOE per BOE to be in this $20 to $21 range per BOE going forward depending on the price of oil. LOE for our tertiary operations averaged $22.26 per barrel in Q4 as compared to $22.54 per barrel in Q3. Although our cost of CO2 increased in Q4 due to the higher oil prices, higher production and lower workover cost caused our per barrel tertiary operating cost to decrease slightly.

G&A expenses increased by $1.6 million from $5.19 per BOE in Q3 to $5.50 per BOE in Q4, due primarily to higher personnel-related costs and lower production as a result of asset sales. In general, we do not expect our asset sales and sale of ENP to have a significant impact on our G&A expenses going forward. I would expect our G&A expense and extra dollars to increase slightly as we continue to add employees during 2011. Our G&A in Q1 tends to be slightly higher due to the level of year-end work.

During the fourth quarter, we had $12.3 million of Encore merger-related costs associated with severance, of which $1 million related to non-cash equity compensation expense. We will continue to have a reduced level of merger-related costs, primarily related to severance to the first part of 2011.

Interest expense, net of capitalized interest, decreased sequentially from $53.3 million to $52.9 million. Capitalized interest was $10.7 million in Q4 as compared to $10.9 million in Q3. Average debt outstanding was $2.8 billion in both Q4 and Q3. Going forward, we currently expect that our capitalized interest will be around $8 million to $12 million per quarter during 2011, increasing throughout the year.

We had no bank debt at December 31, on our $1.6 billion bank credit line and $382 million of cash on hand. We plan to use approximately $150 million of our cash to cover the repayment of $125 million of subordinated debt and to cover premiums and expenses associated with the redemption of our 2013 and 2015 subordinated notes and new issuance of $400 million of subordinated notes due 2021. We closed on our new $400 million notes issuance on February 17, and on that same day, repaid approximately $390 million of notes that were early tendered. We have called for redemption remaining $135 million at 2013 and 2015 subordinated notes that remain outstanding.

The interest rate on our new notes is 6 3/8% as compared to 7.5% on our old notes, which will save us approximately $4.5 million in annual interests. The repayment of the $125 million in subdebt will save us approximately $9.4 million in annual interest. We projected in the first quarter we will record incremental charge of approximately $16 million associated with this redemption related to call premiums and the write-off of unamortized discounts and debt issue costs.

Our anticipated capital spending for 2011, excluding acquisitions but including capitalized interest in tertiary startup costs at Hastings and Oyster Bayou Field, is currently estimated at $1.2 billion. Capitalized interest in tertiary startup costs in 2011 are currently estimated at $100 million. Our estimate also assumes a similar level of capital costs carryovers in 2011 as we had in 2010. For 2011, based on current prices, we currently estimate that our capital expenditures of $1.2 billion will be $100 million to $200 million greater than our estimated cash flow from operations. If full prices in the OS differential remain strong and our level of cash flow supports it, we could possibly increase our capital spending in 2011.

Our DD&A per BOE remained relatively flat at $15.87 per BOE in Q4 as compared to $15.61 per BOE in Q3. Our tax rate is higher in Q4 due primarily to asset sales and the legal entity restructuring that increased our statutory rate by a couple tenths of a percent. Although this change does not seem significant when applied to all of our deferred tax balances, it is a noticeable adjustment. Going forward, I would anticipate our tax rate to be around 38.5%, with current taxes in the range of 4% to 7% assuming we are able to take advantage of certain deductions under the new tax law.

The IRS recently issued a technical advice memorandum that revoked the previous ruling they granted us in 2008, which allowed us to deduct certain tertiary injection costs relating to pipelines and facilities when placed into service. Under the new guidance, we will be required to capitalize and deduct these costs over time. The IRS has granted us perspective treatment on this change which should allow us to deduct the cost of the Green Pipeline in 2010 since it was placed into service by year end. While this deduction kept our cash taxes low in 2010, we essentially used it to offset the gains from our 2010 asset sales. So we won't be carrying any significant federal NOLs forward. However, as part of the new tax law, in 2011, we believe we'll be able to deduct other expenditures that are normally capitalized and therefore expect our cash taxes to be low in 2011 as well. And with that, I'll turn it over to Tracy.

Ronald Evans

Thanks, Mark. As has been the case annually since year-end 2010, DeGolyer and MacNaughton performed an evaluation of our proved reserves for 2010. 2010 was a very busy year in which we had significant reserve additions and decreases associated with sales of non-core assets acquired in the Encore acquisition. Reserve adds from other acquisitions, primarily Riley Ridge, and reserve additions in our CO2 EOR property and Bakken programs.

The result of all of our activity in 2010 increased our proved reserves on an absolute basis to approximately $398 million BOEs, which consists of 338 million barrels of oil, condensate and natural gas liquids and approximately 358 Bcf of natural gas. We added 346.7 million BOEs of proved reserves during 2010 before netting out 2010 production, property sales and reserve revisions, replacing approximately 1,300% of our 2010 production. The majority of which was from our acquisitions of Encore, approximately 222 million BOEs; Riley Ridge, 32.3 million BOEs; additional reserves in our CO2 tertiary properties of approximately 35 million BOEs; and the Bakken, which Phil already mentioned, is about 33 million BOEs.

During the 2010, we also added approximately 15.7 million BOEs in the Haynesville play, but as we previously mentioned, we've sold that property prior to year end and those numbers are not in our year-end reserve report. Our CO2 tertiary-related oil reserves added during the year were primarily at Delhi, 29.5 million barrels. That was our first booking. We had performance revisions at Eucutta of about 0.6 million barrels; Tinsley, 2 million barrels; Lockhart, 1.3 million barrels. Those are all due to raising the recovery factors in various parts of the field. And then finally, we had additional reserves at Heidelberg of about 4 million barrels that are due to having reserves associated with additional [indiscernible] areas we modified some of our patterns. We also had a slight negative revision at Cranfield of about 2.25 million barrels.

Property sales of approximately 130 million BOEs during 2010 were all associated with non-core assets acquired during the Encore acquisition. The net present value using a 10% discount rate of our proved reserves as of year end was approximately $7.3 billion. In comparison, our net present value of the proved reserves at year-end 2009 was $3.1 billion. The increase in net present value from year-to-year was primarily caused by acquisitions, our additional CO2 reserves, our Bakken reserves and then again, approximately $18 per barrel higher oil price.

Proved reserve estimates at year-end 2010 were valued based on the unweighted first day of the month average product prices for the preceding 12 months, which resulted in a NYMEX oil price of $79.43 per barrel and a NYMEX gas price of $4 and approximately $0.45 per million Btu. Compared to year end 2009 product prices calculated the same way of $61.18 per barrel and $4.19 per million Btu. The PV-10 Value of the company's year-end reserves uses an alternative price deck based on the future’s market forward strip as of December 31, 2010, was approximately $9.4 billion.

Denbury's net average price contained in this alternative reserve report were approximately $87.30 per barrel, $57.87 per barrel for NGLs and $5.46 per Mcf for natural gas. The calculated value, utilizing this alternative price deck, which is lower than current commodity prices, yields an estimated net asset value per share in the upper teens and does not include any value associated with our extensive tertiary and Bakken probable reserves.

As of year-end 2010, approximately 85% of our proved reserves are oil, or condensate or natural gas liquids, vast majority of that is definitely oil and 60% of our proved reserves are proved developed reserves. Proved reserves associated with our CO2 tertiary operations now account for approximately 41% of our total proved reserves and total 164.4 million barrels as of year-end 2010. In comparison, our tertiary reserves at year-end 2009 were 134.5 million barrels of oil.

Based on our 2010 capital investment of $4.9 million oil and gas activities and acquisitions, including capitalized interest, our finding cost for 2010 is approximately $14.20 per BOE. In addition to our proved oil and gas reserves, D and M [DeGolyer and MacNaughton] also performed an evaluation of our proved CO2 reserves. Our CO2 reserves at Jackson Dome increased by 1.1 Tcf of CO2 to a total of approximately 7 Tcf of CO2 as of year-end 2010 after accounting for our 2010 production. 2010 CO2 production was approximately 302 Bcf of CO2 that was offset by reserve additions during the year, 682 Bcf were added at Gluckstadt Field based on encountering original reservoir pressure and a new fault walk that we tested. 311 Bcf at our DRI Dock discovery that was drilled in 2010 and we did have a net positive revision due to performance in several of our fields accounting for nearly 100 Bcf of CO2.

We also added an additional 920 Bcf net to our working interest of CO2 reserves in the Rocky Mountain region with the purchase of our interest in the Riley Ridge Unit. At Jackson Dome, we are accelerating our activities to develop additional CO2 reserves in the Gulf Coast. Our objective plans for 2010 call for the drilling and completion of four wells during 2010, two of which are existing proved reserves to add additional rate, and two of which are expected to add additional reserves from testing a portion of our 2.6 Tcf of probable and possible CO2 reserves.

Our original plan was to drill and complete two wells and begin drilling two other wells. With our accelerated plan, we believe we'll get all four wells completely drilled and hopefully completed as well during 2010. We are contracting an additional rig in order to drill the four wells and obviously, we are accelerating the drilling of the exploratory prospect that was planned for later in the year. And with that, I'll turn it over to Bob to talk about the operations.

Robert Cornelius

I'll give you a quick update of the major EOR fields, our production and then the pipeline construction progress we made in the fourth quarter. Tertiary production averaged 31,139 net BOEs for the quarter. That was an increase of 1,608 net BOEs or 4.5 compared to the third quarter of 2010. As Mark said, we had a good fourth quarter that allowed us to exceed our daily tertiary production guidance of 28,750 net BOEs a day for the year.

Now tertiary production increase was led at Tinsley and Heidelberg Field. Both of these fields' response was slightly ahead of schedule. Production at both fields kind of leveled out during the first quarter of 2011. Our experience shows that our tertiary fields will have a period of relative flat production, followed by another ramp up in production later in the year. So expect more from these two fields during second and third quarters of this year, then I'll give you more about field production rates a little bit later.

Other accomplishments during the fourth quarter were the completion and commissioning of the 325-mile Green Pipeline under Galveston Bay and into the Hastings Field. So during December, we also initiated injection into the Hastings Field. Now Hastings Field is our largest potential EOR project to date. Also, Jackson Dome produced a record rate in excess 1.1 Bcf per day. Also, during the period in the Bakken, we picked up our fourth and fifth drilling rigs during the fourth quarter. So adding the Hastings Field to our list of CO2 projects in December was a great accomplishment for our technical team. Denbury now has 16 different areas under CO2 injection in seven of our nine phase expansions.

Overall, we continue to have great success in our CO2 operations with five of our field areas exhibiting double-digit production growth during the fourth quarter when compared to the third quarter. I'll break down and review our CO2 expansion by phase. Phase I is our most mature area, consisting of six field areas in the Southwest Mississippi and Louisiana. It increased by 228 BOE/d over the third quarter with an average production rate of 12,656 net BOEs. Brookhaven's quarterly production increased 11% quarter-to-quarter to an average production rate of 3,699 net BOE/d. Most of that fourth quarter increase was due to the WAG, which is Water Alternating Gas program initiated at Brookhaven back in May.

We now have four completed injection patterns engaged in the WAG process at Brookhaven. The success of the WAG program is another example of the various tools that we use to manage our CO2 injection into the reservoir. Lockhart Crossing also continues to perform better than expected with the fourth quarter production exceeding third quarter's performance by 127 net BOE/d, resulting in a growth rate of 8% quarter-to-quarter. This is the third straight quarter that Lockhart Crossing production has had a significant increase. Mallalieu area decreased slightly at 3.4% or 150 net BOE/d quarter-to-quarter. Mallalieu area, of course, is our mature CO2 flood and production will most likely continue to decline over time. McComb and Smithdale also had a slight decrease of 2% quarter-to-quarter.

Moving to Phase II in Southeast Mississippi. We experienced a 409 or a 4% increase in production rates as compared to the third quarter. Heidelberg continues to perform better than expected with 616 net BOEs or 22% increase quarter-to-quarter. Eucutta Field and Martinville Field were both flat quarter-to-quarter. And on a quarter-to-quarter basis, Soso Field was 188 net BOEs less than the third quarter. The team is working to expand the Bailey and the Soso Field with two patterns which should flatten production during this year.

Phase III is Tinsley. Tinsley increased 10% quarter-to-quarter. The reservoir at Tinsley continues to perform better than predicted and is now our highest volume EOR field with an average fourth quarter net production rate of 6,614 net BOE. Tinsley was aggressively developed during 2010 with an investment in excess of $59 million that added well count, expanded separation and recycled facilities. With the fourth quarter production rates exceeding expectations, we will probably see Tinsley production flatten during the first quarter of this year, with production increase the trend later in the year.

We now have an additional 16 producing wells that should respond during the second and third quarter of this year. Also, during the fourth quarter, we plan to continue the expansion in well work and infrastructure in east fault block, which is the largest fault block in the Tinsley Field. Phase IV is Cranfield and it increased 22% or 188 net BOEs quarter-to-quarter, with an average rate of 1,043 net BOEs. The rate increased due to the completion of six wells and the use of jet pumps that were installed upon initial completion of these producing wells. The jet pumps placed in the wells allow them to respond quicker than waiting for the well to produce [indiscernible] alone. We have used jet pumps in other fields to improve response time in oil production rates. The program works well in Cranfield.

In Phase V Delhi, we completed 20 wells -- 2010 drilling program and other well work has been completed in the field. The production line and injection lines were completed and connected to Test Sites #1 and #2 late fourth quarter and early January. CO2 injection is increasing as the injection lines are connected to these wells. Fourth quarter production averaged 703 net BOEs, which is a quarter-to-quarter increase of 38%. We expect Delhi to continue to respond. Our Phase VIII is Oyster Bayou Field. Development is now moving forward. As you know, we received a core of engineering permit in January. Although that was several months later than what we wanted, construction is now in progress at the Oyster Bayou facility. First fuel oil production in Oyster Bayou Field might occur about a year from now, a little behind schedule due to the permitting delays that we encountered.

I mentioned Hastings already when we started injection during mid-December with the completion and commissioning of the Green Pipeline. With the 325-mile Green Pipeline committed, Donaldsonville to Hastings Field, we turned the team's focus to the 85-mile, 20-inch CO2 pipeline off the Green Line from outside Beaumont, Texas into our Conroe Field. Engineering design proposed right away an environmental permitting at the Conroe Field are now underway, and we currently estimate the pipeline will be completed during 2014.

The 20-inch Green CO2 Pipeline, that is our 230-mile pipeline running from Lost Cabin, Wyoming to Bell Creek in Montana. Right-of-way and surveying are nearly complete with 100% of surveying and 90% of right-of-way acquired. Our 20-inch pipe is physically being manufactured and the comment period for the environmental assessment is now underway. We've had nothing but positive responses so far. We expect the permitting in the next 60 days. The pipeline will be constructed in two segments. The first is the 150-miles of pipeline that have a target construction date starting in August of 2011. Construction in the first segment will wind down near the end of 2011 during the winter months. And then the final segment will be constructed between August and December of 2012.

Work at Bell Creek Field, where the pipeline will terminate, will continue as we prepare the field for CO2 where we're starting on the wells, getting ready for CO2 service, as this work will be completed before the commissioning during the fourth quarter of 2012. Approximately 41 injection wells were prepared for injection during 2010. The team is working and designing the recycling facility and obtaining the proper permitting.

And let's switch now with the Bakken. We now have five rigs operating in that play. Our fourth quarter net production in Bakken was 5,193 BOEs per day. Initially, we expected to complete and bring on approximately eight wells during the fourth quarter. We were only able to complete and place five wells on line during the end of the year. As you know, weather and fraction service have slowed a lot of the activity in the play during December to mid-February.

Several of the storms actually required us to choke back a few of our wells in order to keep them flowing and not to run out of storage tank capacity on the lease, as road conditions were hindering the trucking capabilities. But after that brutal weather during the first half of February, we've now been able to increase a number of frac treatment. We had three frac treatments were completed during the last two weeks and we have four additional frac treatments scheduled during the next two weeks. Two additional completions were also scheduled towards the end of this first quarter. So while production rates are less than expected during the fourth quarter, we expect to meet our original expected first quarter exit rate assuming we have no other major weather issues out there.

The other thing we have in the Bakken is we have five confirmed frac-ing dates per month through the end of the year. And I think we're making some pretty good progress in the Bakken. During January, we completed the Franchuk 34-19NWH and the Franchuk 34-19SWH. Those wells had IPs of 1,957 and 2,006 gross BOEs respectively. Both wells were completed in the middle of Bakken and located in Murphy Creek area. We also have good preliminary results from our Thompson 31-11. That's a northwest horizontal in the middle of Bakken. And that's in the Charlson area well and we completed it last week. And although we are still on flow back, the well looks pretty strong.

The latest Bakken well activity is available on our website. We break down each well, where we are. It's in our corporate presentation towards the end, Page 37, 38 and 39. That's, again, on the website. One last thing, we also are evaluating, picking up or engaging in another drilling rig to test our Almond or Northeast Foothills area later this year. We want to try to evaluate that. And with that, I'll turn it over to Phil.

Phil Rykhoek

Okay. Thanks, guys. Lots of good data there. Tony, if you could come back on, let's do some Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question and queue from the line of Mitch Wurschmidt with KeyBanc Capital Markets.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Just wanted to talk a little bit more on the WAG benefit that you guys continue to kind of get here. It looks like you got Brookhaven all the sudden a nice increase and I believe you were going to do a WAG also in Mallalieu. Are you seeing much benefit over there? Do you think you’ll see that soon? Kind of how long is it taking to get the benefit of the WAG? And also just curious on your proved reserve bookings, did you see any kind of increases due to the WAG enhancements?

Ronald Evans

I do not believe we have any results from Mallalieu at this point. We are going to look at that. Of course, Mallalieu, we already have a fairly high recovery factor projected so in that case, it's probably slightly incremental. Brookhaven, obviously that's an area where we’ve instituted the WAGs because we've had some premature breakthrough in a certain pattern. And so in that area, there really weren’t any reserve increases due to the WAGs as we're just trying to getting a better areal sweep to recover the reserves that we've currently booked. So again, I mean, the WAGs are a tool that we use. We use them in areas where we've either had premature breakthrough like at Brookhaven or in areas like Little Creek and Mallalieu where we have relatively high recovery factors already and are just trying to get a little incremental. I don't know the exact number, what the incremental would be from the WAGs, but it would be a small part of those revision numbers.

Ronald Evans

That's just another tool like Tracy said. I mean, we've used polymers. We've even used perforating density, cement squeezes, path or separate, choke down, old chokes. We have a whole array of things in our toolbox. It’s true that WAG at Brookhaven really helped us a lot this quarter.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

But I guess, are you then surprised by the benefit at least Phase I you've seen on a lot on these floods? It looks like you just continue to kind of outperform and get nice performance out of those older floods.

Ronald Evans

Yes, I mean, definitely. Like at Little Creek, we've definitely seen some positive results from it. And when you look at it on a quarter-to-quarter basis, the production rates, I remember, this third quarter and fourth quarter, we had one well that hadn't responded in almost three years, go to 400, 500 barrels a day. Obviously, that's going to impact your production schedule. Yes, it's a great tool. We're going to continue to utilize it in areas where we believe we can increase the ultimate recovery or in areas where we have issues with the gas breakthrough. I mean, WAGs have always worked. I mean, that's the way all West Texas is flooded. It's just, we use it more as a tool. We have, like I say, a premature gas breakthrough issue or in areas where we're just trying to increase the recovery factor incrementally.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And Mark, on the LLS benefit, I'm just curious, you mentioned the $100 million to $200 million you'll be spending kind of above cash flow. Are you baking in that LLS benefit in that assumption or kind of how long you kind of baking it in? Kind of thinking about that in our model.

Mark Allen

Not very long at this point. We're still staying fairly conservative, I think.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And just any update on sort of sourcing the CO2 in the Rockies, LaBarge. Any kind of an update over there?

Ronald Evans

We're still having a lot of conversations but we've not got anything to raise a report at this time. But we are -- we think we're making progress, but again, until we actually can ink something, we can't really announce it.

Operator

Our next question in queue, that will come from the line of Jason Wangler with SunTrust.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Kind of on the same question as before, the LOS, did you say that the following month is when you'd actually receive that benefit? I just wanted to make sure I heard that right.

Mark Allen

That is correct. The average of the LOS differential for, say, the month of February will impact on March pricing.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

And then just on the potential to ramp some things up. Is there a couple of things you see on the tertiary side that you could maybe move a little bit more forward, obviously, those things being kind of longer-term projects? Or would you just look to go up to the Bakken and maybe add a sixth or seventh rig?

Mark Allen

We're kind of looking at it. I mean, they're all kind of small but they're going to maybe start adding up. As Tracy mentioned, we've accelerated Jackson Dome spending a little bit. We've added – probably going to get an extra well there, maybe an extra two, depending on kind of how you measure it. We think we kind of need to test the Almond and Northeast Foothills acreage and either prove that up or disprove it. So that would be an incremental expenditure. We have, actually, a little bit of conventional spending that we kind of took out of the budget because we were just trying to get down to a certain number and we got a little bit we can spend there. I mean, it's hard to accelerate EOR that maybe is -- maybe are a few things we could do slightly fast, too, but because it’s [indiscernible], you can't just go twice as fast on that. That just doesn’t happen.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

And then finally, those recent Bakken wells look like they were very strong as opposed to some of the other ones that were pretty good before. Was there anything besides more frac that you did differently there or is just you guys getting a little bit more comfortable drilling a lot of wells up there?

Ronald Evans

I think it's probably just getting more comfortable. We are working to experiment in volumes versus stages and sand into these and those type of things. I do think there's just heterogenousy in the reservoir. It's not a blanket and I think we found a good area there. I do think that the team is getting more comfortable. As you can see, we're ramping up the number of fracs we're going to add this fourth quarter.

Operator

My next question in queue, that will come from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

Just on top of the question on CapEx, potential increase. How much would you be willing to sort of accelerate things? Are we talking like $100 million, a couple of hundred million dollars, what is the thought process on how much you guys could actually increase?

Mark Allen

A lot of it just depends on commodity prices and cash flow. I mean, we feel pretty comfortable. We have a balance sheet that's very strong right now. We have virtually no bank debt, an unused line. But we did our budgeting. Last fall is when we kind of started doing it and, of course, commodity prices have continued to firm up. So yes, I mean I think they're talking $100 million to $200 million. I don't think it's much more than that. But we're just kind of monitoring it day by day. And as I said, we're kind of slowly adding a little bit here and there.

Scott Hanold - RBC Capital Markets, LLC

And for the most part, and correct me if I'm wrong, this is probably not going to -- that increase probably wouldn't have as much of a significant impact on your production expectations this year, is that right?

Mark Allen

I don’t think it will have much, no. Most of it's more longer-term, like for instance, Jackson Dome. I mean, that's part of our long-term project there.

Scott Hanold - RBC Capital Markets, LLC

And going to Tinsley and Heidelberg, you also just seen some stuff kind of flatten out in the first quarter and can you just try to logistically tell us why that happened? Is it just because it's all relative to the patterns you're drilling that's coming online or why does that occur and what's going to cause it to sort of accelerate in the back half of the year?

Ronald Evans

Scott, this is Tracy. I mean, the issue is we're projecting these things on average response times. And so in the fourth quarter, we got some responses ahead of schedule and therefore, our next ones are scheduled at a certain period of time. So what that leads to is potential flat period. We've seen this in not just in these fields. We see it in a lot of fields. We ramp up and there could be a flat period and then they ramp up again. It's not really the patterns we've started or these patterns versus those patterns. It's really in how we're forecasting it and unfortunately, the only way we really know how to do it and have been doing it fairly well recently is to forecast this average production response time. And so if you get some responses early, you're probably going to see a little flattening. And then once you get the next phase ramping up, then you will see the increases start again.

Scott Hanold - RBC Capital Markets, LLC

So it’s just a relative timing of the phases within -- with the phase within each phase relative to -- versus like a particular well that's been going to sort of have, sort of an increase flattening and then increase again. Is that correct?

Ronald Evans

I mean, the well will go up flat now based on our model and then it declines. So yes, I mean, the overall model has that component into it. So it is a timing issue, when does the next either well or wells start increasing.

Scott Hanold - RBC Capital Markets, LLC

You all talked about testing, obviously, some of that more extensional Bakken acreage Almond area. When does that stuff expire? When do you have to test it before it kind of goes away?

Ronald Evans

There's a variety of times. I mean, I think a lot of it goes out in 2012. And some of it actually, a few acres go out now. We’re looking at it now, what we need to do to the test the area. There's been some more activity in the area that's kind of giving us some encouragement.

Mark Allen

The bigger chunks are starting next year and so we just feel like we have to do some testing to decide if we want to -- what do we do with the acreage, and it's not been. Northeast Foothills has had some activity up there and that actually is looking like that may be promising. Almond really is, has had nothing happen on it so far since we owned it.

Scott Hanold - RBC Capital Markets, LLC

And remind me because I know you guys, I think it was last quarter, the quarter before that kind of I guess reassessed your Bakken acres and indicated it was 902. Is any of that stuff up there part of the 902?

Ronald Evans

Yes, about 70,000 or so.

Mark Allen

Yes, it's about 60,000 in Almond and maybe 10,000, 15,000 in Northeast Foothills.

Operator

Our next question in queue that will come from the line of Scott Wilmoth with Simmons & Company.

Scott Wilmoth - Simmons

What are your thoughts on acquisitions in 2011? And can you just comment on kind of the environment for picking up oil properties in that current price environment?

Mark Allen

We continue to pursue acquisitions. I think they are perhaps a little bit slower maybe, or maybe put another way is more of a hesitancy of companies to sell all properties because a lot of people seem to be seeking oil production and obviously like the cash flow and so forth. But, Scott, that's just extremely difficult to forecast. We continue to talk to people and if the right opportunity comes along, we'll do it. Obviously, we're not inhibited by our balance sheet.

Scott Wilmoth - Simmons

And I would assume most of that focus would be on tertiary and then if you guys, are you guys targeting Gulf Coast and/or Rockies or it's just whatever the best opportunity is?

Mark Allen

I mean, it’d almost certainly be an EOR property unless it comes in a package with something else and you have the Gulf Coast or Rockies, would be happy to get either one.

Scott Wilmoth - Simmons

And then I'm thinking down to 2015 or so in the Gulf Coast once Conroe gets ramped up. How much excess capacity will you guys have on the Green Pipeline for potential additional phases down the road?

Ronald Evans

The pipeline will depend on where the sources are coming in. So I mean, obviously, we're talking to sources in the Gulf Coast -- I mean, in the more Houston, Southeast Texas area. So hopefully, we can get some [indiscernible] sources down there. I mean, the Green Pipeline itself, if you flow it from Donaldsonville to Hastings, has a maximum capacity of about 800 million a day. But obviously, you bring in sources closer, then you can start bringing that pipeline capacity higher. But it all depends on where the sources are to really give you an idea.

Scott Wilmoth - Simmons

And do you guys have any update on potential sources from Mississippi Power?

Ronald Evans

We don't have any update other than we continue to have discussions with multiple people in the Gulf Coast, just like the Rockies. We think we're close. But again, until we actually have some ink on some paper, it's kind of hard to talk much about it.

Mark Allen

They have broken ground.

Ronald Evans

They have broke ground, if that was the question.

Mark Allen

But we're still working on the contract with them.

Operator

[Operator Instructions] And our next question in queue will come from the line of Xin Liu with JPMorgan.

Xin Liu - JP Morgan Chase & Co

What you have seen on the cost side in the Bakken?

Mark Allen

We're looking around 8 to 8.2 right now, is where we are right at this point.

Ronald Evans

We ended the year at 7.5, relatively speaking.

Xin Liu - JP Morgan Chase & Co

And your budget is around 8.2-ish for turning it over?

Ronald Evans

Our budget is around $300 million for the Bakken.

Xin Liu - JP Morgan Chase & Co

Right, I mean, on per well basis.

Robert Cornelius

On a per well basis, I think we're looking at between 7.5 to 8.2. Depending on where it is, what number of stages is frac, whether it's a 6.40, a 12.80. It depends on a bunch of parameters, where they're located and how we're going to treat them.

Ronald Evans

Yeah, costs have increased up enough to impact on our budget to a really serious degree. They are creeping up, but we had estimated somewhere in that 7.5 to 8.2 range.

Operator

Our next question in queue, that will come from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Looking back at the Rockies and CO2 up there, you mentioned that you've continued to have discussions with the folks who control other CO2 sources. I remember you guys mentioning perhaps in the fall that the Riley Ridge acquisition had the potential to send a message to some of the other sources that there are other options out there for us. Has the negotiation process gotten any easier as a result of that? And second, I'm curious whether sort of the traditional pricing structures we've seen for CO2 contracts are what you're largely talking about or whether people are looking at some different sort of structure for pricing?

Ronald Evans

As far as pricing structures, I mean, as far as a base price with an escalator to oil, that's pretty much the same. We haven't seen any change in that regard. As far as sending messages and has that had any impact, I'd say it's hard to tell. I mean, the eventual answer is we have to make a decision whether or not we go capture the CO2 at Riley Ridge and bypass potentially these other sources. So we're still talking to them. I mean, again, while the key in the CO2 business is trying to get it as close to your EOR sites as you can because transportation cost is a significant component. So that's still what we're trying to do is get CO2 at the lowest levered price.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And as far as the regulatory environment up there, I know for a while the CO2 emitters were feeling a lot of pressure, I want to say it was from state of Wyoming. To show that they had a plan for their CO2 and that they were not going to vent it as some of their potential targets matured, is that same degree of sort of push still there?

Ronald Evans

The Wyoming governor used up his term and now we have a new one, so we're waiting to see what kind of pressure. I do know that the Wyoming Corporation Commissioner -- Wyoming Oil and Gas board, they make these guys have hearings every year to explain what they’re doing. So I suspect that will continue.

Noel Parks - Ladenburg Thalmann & Co. Inc.

As far as for 2011, this is for the current CO2 injection phases. Where are the reserve bookings for 2011 most likely to come from as far as the fields that will reach that threshold where you can demonstrate they’re producing?

Ronald Evans

I mean, right now, the only real big preserve booking would have to be a Hastings response or a Oyster Bayou. But the facility delays we’ve had there, although we have permits now, we're looking at maybe it occurs in ’11, most likely ’12, but reserve bookings -- we may get some response but it’s not going to be significant enough to get reserve bookings. It’s probably debatable at the point. So I think you're looking at primarily at ’11 Bakken and then hopefully we can get some more performance revisions at some of these CO2 floods.

Mark Allen

Yes, I mean, ’11 is probably going to be a light year when it comes to new fields but ’12 could be a banner year because you should have production response at Oyster Bayou and Hastings. So as we've talked before, our proved reserve bookings are a little bumpy, but that's just -- it has to correlate with when we get production response in the field.

Operator

And our next question in queue, that will come from the line of Richard Tullis with Capital One Southcoast.

Richard Tullis - Capital One Southcoast, Inc.

Can you tell us what the current production is at Delhi?

Mark Allen

It’s not because we don't know, it's because we'd rather not give out interim data, particularly on a per filled basis.

Richard Tullis - Capital One Southcoast, Inc.

I know you had mentioned the impact of weather on 1Q production, how much do you think has been deferred up to this point?

Robert Cornelius

I think in the Bakken, probably a couple thousand to 2,500 barrels per day. If we could have got all those fracs off, I think we would've seen a lot higher production in the Bakken area.

Mark Allen

I mean, we're probably running 30 to 60 days behind because of weather and so you just push the growth out a little bit. As Bob mentioned, we think we'll still hit the exit rate for the end of the first quarter, probably pretty much on track, it's just we lost a month to month and a half of incremental production.

Robert Cornelius

Just anecdotal, Lynn Helms, who runs the North Dakota Industrial Commission, regulates oil and gas. He made a comment. He puts out a monthly statement that gives the well count and the production and those type things. And he made the comment that he believes that during the heart of ice and snowstorm, that they had a million barrels that were curtailed in tanks and in chokes because they could not get the trucks onto the field to pick up the crude oil. And we had several wells that we had to pinch back on a small choke because you got to keep the fluids moving. So we kept the fluids moving until we knew that we had the tank capacity on lease to move that. So I think that also impacts us. What's the right number, I don't know because you’re gauging a lot of different tanks and doing a lot of different things. But I think you're going to see us, like we said, hopefully within a nice exit rate.

Richard Tullis - Capital One Southcoast, Inc.

What's the current price you've been getting up there in the Bakken recently, oil price?

Mark Allen

We've been historically $10, maybe even a little more. And I think fourth quarter was actually a little bit more than double digit. But I’m not sure what the current price is.

Robert Cornelius

I'm not sure. I think we've historically seen more tender levering range. And I think in Q3, Q4, we were higher than that. Probably more like $13 in Q4 and I think after November, we should've seen differentials kind of return more towards normal. So maybe the $10 to $11 range is my best guess at this point.

Richard Tullis - Capital One Southcoast, Inc.

As you think about the Bakken, I mean, any plans to JV or monetize some of the acres there?

Mark Allen

No, as I've kind of said, probably it's a great asset. But it's not necessarily a core asset. So we have explored options and we've talked for quite a while. We'd love to trade it for oil property that hasn't gone all that well. So I don't know if that's too promising. But we're still looking. I guess the short answer is we're exploring options and if the right thing comes along, we'll do it. And if not, we're quite happy to keep it and develop it.

Richard Tullis - Capital One Southcoast, Inc.

The tertiary projection for 2011, is it still a good number, the 32,500? Or are you going to try to make up any shortfalls somewhere else or. . .

Mark Allen

That's still our best estimate at this point.

Operator

Our next question in queue, that will come from the line of Mike Scialla with Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

You had mentioned a couple of times the exit rate on the Bakken for the first quarter, I may have missed it, but what is that exit rate you're targeting there?

Mark Allen

I don't think we gave a number.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

I guess, switching over to the CO2, you talked about accelerating at Jackson Dome, that's first exploratory prospect. What kind of potential do you see in there?

Ronald Evans

I mean the numbers are very large. I mean, we're really – we’re not giving out, but it’s like most of those structures up there, you can have potentials up to two to three Tcf.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

So that means it could be another dry ice type of CO2 that’s successful?

Ronald Evans

Yes, potentially.

Mark Allen

Yes.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And at Riley Ridge, the 902 Bcf there, is that all undeveloped at this point or is any of that developed?

Ronald Evans

I mean, I really have to look at the reserve report. There’s probably some of it at ENP because I know there’s at least one producer been drilled but you're still building the facility so it could technically all be [indiscernible] because of the sitting capital that has to be spent this year. But it's expected to come on in the third or fourth quarter. I mean, they've been working on the facility during these construction seasons and expect to come on late third quarter, early fourth quarter. So sometime in 2011.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Are you doing any drilling there now?

Ronald Evans

I don't believe there's a drilling rig running right now but there is...

Robert Cornelius

There's going to do some completion work and they got some wells already drilled and they’re going to do some completion work when the weather breaks and then they'll be ready to produce in the third and fourth quarter like Tracy mentioned.

Mark Allen

When the facility is ready.

Robert Cornelius

When the facility is ready.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And since you're reluctant to talk too much about Delhi production. But I think you have said in the past that it is running ahead of schedule, is that performance related or is that just more of a timing issue? And could there be any upside to that 38 million barrel potentially you talked about there?

Robert Cornelius

No, we're not going to be able to add anymore reserves. The reserves right now, we won't add any reserves until we get a lot more performance out of the well. I think what you're looking at, where we where production wise, it came on earlier last year, 2010, than what we had expected. If you will recall, don’t want to rehash stuff, but back last year, we had a flow line issue. We got that resolved and so then it started to ramp back up. So we are putting CO2 in the ground at a rapid rate. Facilities are being -- test stations are being connected. So we hope, just like these other fields, that we start to see it maybe ramp up later in the second, third quarter results.

Mark Allen

It's performing well.

Robert Cornelius

Yes. But there won't be any more reserves added this year.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

I mean, it sounds like performing as expected at this point, is that fair?

Ronald Evans

Yes.

Robert Cornelius

Mike, Riley Ridge is all PUD.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And then up at Cranfield, I know you talked about the reserve right down there and that first pattern, I guess didn't perform the way you'd hoped. Was that right down because of that performance and then have you figured out the problem there? It looks like you've re-established growth. Did you figure out what went wrong with that first pattern?

Ronald Evans

The first answer is yes. That's where the provision was. Actually, I think it was the first couple of patterns. We believe that the best we can tell is that area was essentially swept through the gas cycling operations that occurred back in the 50s, 60s time period, and so we think that's what's primarily happened there. We haven't seen it anywhere else so yes, we feel comfortable going forward on the remaining patterns.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

One last one back on the Bakken, the Almond and Foothills area. You said some competitor activity has encouraged you. Can you talk at all about what kind of EORs and costs you may expect up there?

Ronald Evans

I don't think the cost would vary that much. I think Northeast Foothills is technically a little shallower, so it’ll be a little bit cheaper. But I don't know if there's any really good numbers yet to report in terms of expected EORs. Almond, there really hasn't been much near there. We'll probably be the first one to drill out there in several years.

Operator

Our next question in queue, that will come from the line Sven Del Pozzo with IHS Energy.

Sven Del Pozzo - John S. Herold

Regarding the Keystone Pipeline, do any Bakken producers, as far as you know, can they get their oil into that pipeline or you haven't heard of anything like that?

Ronald Evans

Talking about the one that’s to be constructed or...

Sven Del Pozzo - John S. Herold

The one that's going right through the eastern part of North Dakota. I was thinking maybe some Bakken producers on the eastern side might be able to access it?

Ronald Evans

I believe, and we’d have to double check, but I believe that they have offered space. And whether or not anybody is actually using it, I don't know.

Sven Del Pozzo - John S. Herold

And at Riley Ridge, you did mention the presence of some other gases associated with the natural gas. So in your reserve report, I'm just wondering what might the schedule be for the production of that gas and are there going to be – essentially, are you going to have to deal with that gas, treat it prior to its production, which might push out its date in terms of when it first becomes, when the first gas comes out of there, at least natural gas?

Ronald Evans

The production stream out of Riley Ridge would be very similar to what is coming out of [indiscernible]. So it's well known what it is. It's roughly 65% to 70% CO2, 20% methane and then you have about I think it's 0.5% helium. So the plan is to separate the methane and the helium from the H2S and CO2 and then secondly, separate the methane from the helium. Sell those two products and reinject the CO2 and H2S at this point in time.

Sven Del Pozzo - John S. Herold

So then does that going to require some big upfront in capital expenditures? I'm just kind of wondering when the timing of that...

Ronald Evans

It started being constructed last year and it should finish constructing this year and first production will occur in the third or fourth quarter of 2011.

Sven Del Pozzo - John S. Herold

Then on the SEC reserve report, I was wondering if there's a future development cost number that I might associate, that I can tie to your reserve report. And Phil, could you get me in the ballpark on the pipeline cost that -- so if costs are not directly related to drilling wells.

Ronald Evans

Well, in our proved reserve report, the future development cost is about $1.8 billion. Zero of that is, there might be some flow lines in there but there's no -- Green CO2 Pipeline is considered probable because that's where the probable reserves are.

Mark Allen

All the future pipelines expenditures related to probable phases, I mean the Green CO2 is in the range of $275 million to $300 million. We don't really have a good number on Conroe yet, but it's probably something less than $200 million. And we're just continuing to add infrastructure as we continue to add field.

Sven Del Pozzo - John S. Herold

And is Conroe in there? Did you say that the pipeline expenses for Conroe are in that $1.8 billion number or no?

Ronald Evans

No.

Robert Cornelius

Conroe is probable, so its pipeline is probable as well.

Sven Del Pozzo - John S. Herold

Who are the major non-op guys like [indiscernible] to drill wells in the Bakken in the fourth quarter, just if you want to mention a couple of the major ones.

Ronald Evans

There's many, many of them. Continental...

Sven Del Pozzo - John S. Herold

I know there's a lot. I was hoping if you could give me a little better idea.

Ronald Evans

It's everybody. I mean, we have probably two or three from all of them.

Robert Cornelius

We have Petro-Hunt, Newfield, Rigum [ph], Continental, XTO, Petro-Hunt, Riley. I mean, I'm just reading the list of our non-op wells that we have, and those are the operators that we have, or we do dealings with. They’re on both sides. They’re in ours as well as we’re in theirs. It's not our position.

Sven Del Pozzo - John S. Herold

So not only on a gross basis but also on a net to Denbury basis, it's the same kind of influence?

Ronald Evans

Well, you're talking from a reserve? I mean, we do have a much higher percentage of reserves that are operated than we do are not operated. It's probably 80, 20, something like that, maybe 75, 25. But yes, we have the same people involved whether it's not operated, whether we’re operating, whether they’re operating, it tends to be a lot of the same characters.

Operator

The next question in queue, that will come from the line of Nick Pope with Dahlman Rose.

Nicholas Pope - JP Morgan

I've seen some stuff just on some legal issues that I think you are going through with Green Pipeline and I guess going to the Texas Supreme Court, is there anything there that we should be worried about in terms of timing, of getting CO2 through this pipeline or is it just going to. . .

Phil Rykhoek

CO2 is moving through the pipeline right now. We started Oyster Bayou in June of last year and then we finished out 50 or 60 miles underneath Galveston Bay and into Hastings. So we are moving CO2 into Hastings now. So the pipeline’s been commissioned. It's really just a legal issue, a right-of-way issue, a damage issue. And we probably -- that's about all we need to say about it right now.

Operator

Our next question in queue, that will come from the line of Eugene Lipovetsky with Zimmer Lucas.

Eugene Lipovetsky

Quick question on the Williston. Mid-year last year, you guys added about 15.2 MMBOE of reserves and then by year end this year, recently, you guys said you actually have 33.4 MMBOE of booked reserves in the Williston Basin. I'm wondering how much upside there is to those numbers based on the fact that those bookings, from what I understand, only really reflect one interval in the Williston Basin and I'm pretty sure that, that's the Bakken. So how much more upside to the reserve numbers is there to come in the near term from you guys testing the three forks and the other intervals?

Ronald Evans

The number is significant. I think, today, I don't have the exact number of PUD locations that we have. But our total number of locations is in the neighborhood of potentially 4,000 to 5,000. That's quite significant.

Mark Allen

We haven't changed our probable number, 3P number we said was 350 million barrels. So we’re still staying with that, which really didn't have much in the Almond so that could be some [indiscernible] that work. And there's some highly rich stuff up there. But we have just under 50 million barrels of total proved. So if you will, we have 300 million barrels of potential if that's what you're asking.

Eugene Lipovetsky

Well, I'm asking whether that potential number includes any three forks, So could that. . .

Ronald Evans

Our number includes basically three locations. This is proved probable and possible up to three locations per section or per unit per reservoir, yes. So it's in those now. We are hearing people kind of start claiming you could do four so we haven't included that. But we do have some standard size three forks in our 3P number.

Eugene Lipovetsky

And also the EORs you guys are quoting most recently, they kind of went up to I think 525 MMBOE, correct?

Mark Allen

That’s kind of the median. There's actually a range of. . .

Eugene Lipovetsky

I understand this range, but probably the median for simplicity, if I use the median, I pretty much blow through your number. If I use the median, I multiply it by three and I multiply it by your acres, even outside of the Almond. So I guess my question is, could you also potentially have increased bookings just from better well performance in the nearer term?

Ronald Evans

It's possible. If the wells perform better than our forecasted rates, which, it’s hard to tell. I mean, you really need probably, in my opinion, nine to 12 months of data to really confirm that it's outperforming what you originally predicted. It's kind of hard in the first few months.

Eugene Lipovetsky

So seems like you're only assuming three wells per section. So potentially, one of them is the three forks.

Ronald Evans

Three wells per unit per reservoir.

Mark Allen

So six.

Phil Rykhoek

So there’s a total of six. Three in Bakken and three -- and the last three forks.

Eugene Lipovetsky

And my next question is on some of your Gulf Coast properties. I know you previously explored doing something in the Tuscaloosa and given the strength and LLS pricing, which I guess is right in the neighborhood, has there been a renewed interest in potentially exploring ways to monetize that asset?

Ronald Evans

Well, we are looking at talking to people. We've been talking to people for a while about trying to bring somebody in to see if they can move that play forward. They can be our preference that our capital could be very, very small but we still have, I think it's in the neighborhood of 130,000 to 140,000 acres in the Tuscaloosa marine shale and we are looking at the possibility of having somebody else try to take that play forward for us.

Operator

And we do have a follow-up question in queue from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I’m sorry if this was mentioned already, but I just wanted to check, for 2012, the second half of the year, is that pretty largely unhedged at this point?

Mark Allen

Yes, I guess. Virtually unhedged at this point other than stuff we might have inherited in the Encore merger.

Noel Parks - Ladenburg Thalmann & Co. Inc.

So with the uptick we've seen in the futures curve, you have enough potential to do some adding on into 2012 then?

Mark Allen

Yes. We're still doing this 12 to 18 months out so you’ll see us put hedges in exactly within '12 as the time moves forward. But we're trying to kind of keep 12 to 15 months kind of protected.

Operator

And at this time, we have no additional questions in queue. Please continue.

Phil Rykhoek

Okay. Thank you, everyone. Just to give you a quick looking forward to the calendar, I think our next equity conference will be the IPAA conference in New York. That's around the middle of April, and we may do a few one on ones around that date, and then we are finalizing our plans for the spring Analyst Conference. Tentatively, we're looking at the week of May 23. So I think everything is looking good and we expect another great year as we continue to build on our profitable lower risk oil platforms. So we'll talk to you again soon. Thank you for listening today, and we'll talk later. Thank you.

Operator

Thank you. And ladies and gentlemen, that does conclude your conference call for today. We do thank you for your participation and for using the AT&T executive teleconference. You may now disconnect.

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