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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, Director 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

Jason Wangler - SunTrust Robinson Humphrey, Inc.

David Kistler - Simmons & Company

Cory J. Garcia

Noel Parks - Ladenburg Thalmann & Co. Inc.

Denbury Resources (DNR) Q1 2011 Earnings Call May 5, 2011 11:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the First Quarter 2011 Earnings Release. [Operator Instructions] As a reminder, this conference is being recorded. I'd now like to turn the conference over to our host, Chief Executive Officer, Mr. Phil Rykhoek. Please go ahead.

Phil Rykhoek

Hello. Welcome to Denbury's first quarter conference call. I would like to remind you that our following discussion may contain forward-looking statements and that actual results may differ materially. If you needed other information on that, please see our SEC documents.

With me today, I have Tracy Evans, our President and COO; Mark Allen, our Senior Vice President and CFO; Bob Cornelius, our SVP of CO2 Operations; and the newest member of our senior team, Craig McPherson, SVP of Production Operations. Tracy will introduce Craig to you in a moment. Since he started Denbury this week, we won't make him present anything, but you'll see much more of Craig in the future.

Our bottom line results this quarter were strong, with adjusted net income of $103.9 million as compared to only $17.4 million in the first quarter of last year and $86.9 million in last quarter, Q4 of 2010. Correspondingly, adjusted cash flow was $271.2 million as compared to $66 million a year ago and $247.5 million last quarter.

Of course, the reported book operating results are quite different, but Mark will walk you through that reconciliation, which will adjust for the non-cash and nonrecurring items. As we suggested in our year-end conference call a couple of months ago, our production was generally flat this quarter as compared to last quarter, the fourth quarter of 2010. As Mark and Bob will explain in more detail, the EOR production hit a temporary plateau at 2 of our significant fields, Tinsley and Heidelberg, although we expect growth to resume later this year. We have not changed our 2011 anticipated EOR production guidance of 32,500 barrels a day.

In the Bakken, the production increased, although at a slower rate than anticipated, primarily due to the tough winter but in that case also, we have not changed our 2011 production guidance. We have some positive IP rates to give you in the Bakken and some of our most recent wells in the Cherry area, but I'll let Bob tell you about that.

Although 2010 was filled with large transactions led by the Encore acquisition and subsequent sales of noncore assets, we continue to pursue our transaction involving CO2 and CO2 EOR. During the first quarter, we closed on a transaction in Heidelberg and signed a joint venture covering the Tuscaloosa marine shale assets. We signed 3 CO2 purchase contracts with industrial sources, which have a very high likelihood of delivering our first man-made volumes of CO2, supplementing our natural sources. Tracy will provide more color on these transactions.

I do want to mention one other thing. With the stronger oil prices, our stocks become a bargain relative to net asset value. I know that sometimes investors put their capital in the stock because of the limitation on the cash flow multiple, but I want to remind you that our proved net asset value is just over $20 a share at $100 oil, around $24 a share at $110 oil. Note this is a proved-only net asset value using the approximate 400 million BOEs of proved reserves that we had at year end. We have over 1.2 billion BOEs of 3P reserves, which is our proved plus probable and possible, but they're all relatively low-risk potential as they're almost all EOR for Bakken. We even have additional potential running room beyond that as the DOE has suggested that up to 10 billion barrels of oil could be recovered with EOR in the 2 core operating areas. That potential is significantly larger than the popular Bakken play, which I believe is generally regarded as around 4 billion barrels of total recoverable potential. Bottom line, with all of our potential incremental reserves, we should be trading well above our proved net asset value regardless of the cash flow multiple.

But let's get back to the quarter and look at the first quarter details and we'll start with Mark's review of our numbers. Mark?

Mark Allen

Thanks, Phil. As reported in our press release, Denbury had adjusted net income for the quarter of $103.9 million or $0.26 per common share. Adjusted net income is a non-GAAP measure that excludes certain items such as fair value hedging gains and losses and other unusual or nonrecurring items. In the first quarter, we had fair value hedging loss of $172 million, a loss on early extinguishment of debt of $16 million and Encore merger-related costs of $2 million. A reconciliation to get from adjusted net income to our reported net loss, on a GAAP basis, of $14.2 million is included in our press release.

Our adjusted net income was approximately 20% higher than our Q4 adjusted net income of $86.9 million and our cash flow from operations before working capital changes also increased nicely from Q4, up 10% to $271.2 million.

My comments will primarily focus on the sequential results of the first quarter of 2011 and fourth quarter of 2010.

Our total company production for Q1 was 63,604 barrels of oil equivalent or BOE per day versus our continuing production for Q4 of 63,712 barrels of oil equivalent per day, which is our Q4 production adjusted to exclude production associated with all the asset divestitures, including the sale of our Haynesville, East Texas, Cleveland Sand Play and Encore Energy Partners in Q4.

Our tertiary production averaged 30,825 barrels per day, essentially flat with the 31,139 barrels per day in Q4 as previously indicated. Our Bakken production averaged 5,728 BOE per day compared with the 5,193 BOE per day, a 10% increase over Q4. Bob will go into more detail on our production results in a few minutes.

Our average oil price received, including derivative settlements, was $92.72 per barrel in Q1 as compared to $79.18 per barrel in Q4. Our NYMEX oil price differential was $0.59 per barrel below NYMEX in Q1 as compared to $3.90 per barrel below NYMEX in Q4. Our tertiary production differential was a positive $4.33 for Q1 as compared to a positive $0.90 for Q4.

Differentials in our northern properties returned to more normal levels after being impacted during a portion of both the third and fourth quarters as a result of a temporary pipeline shutdown.

As I mentioned in the last quarter conference call, from late January 2011, the Light Louisiana Sweet or LLS oil price has traded at a significant premium to the WTI NYMEX oil price. Throughout most of 2010, LLS 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 current traded LLS differential is the June trade month and therefore, the current differential will impact our June pricing, i.e. it lags one month. Also there are other pricing components that go into the pricing formula, so we may likely not always realize the full benefit of this differential. But generally, it will be within a few dollars of it.

Based on the current market, we currently anticipate that our company-wide NYMEX differential should be a little better in Q2 2011. However, we are not sure how long the LLS differential will remain at these levels. We have continued to layer in additional hedges on our oil production using cost-us callers [ph] and we are currently hedged at roughly 75% to 85% of our anticipated crude production through the end of 2012.

With our most recent hedges added for the second half of 2012, we increased our floor price from our typical $70 to $80, and our average ceiling price is around $128 for that same period. Most of our oil hedges for 2011 have a floor price of $70 and a weighted average cap of around $100. However, it is important to note that we have contracts in 2011 with caps ranging from the low 90s to $106. So even if prices go back to near $100, we will have some exposure to cash hedging losses.

Since our crude oil contracts are NYMEX contracts and we sell approximately 40% of our crude oil under contracts that currently receive prices significantly higher than NYMEX, we will still receive most of that positive differential. To provide a simple example, if WTI is at $110, our hedged ceiling is at $100. And LLS is selling for $125, our net price would be around $115 or the WTI ceiling price of $100 plus the LLS differential of $15.

We paid approximately $5 million for settlements on our oil hedges in Q1, but our cash settlements on our gas hedges provided us $6.6 million in Q1. Although our lease operating expenses were down approximately 3% from Q4 to Q1 due to our property sales in Q4, our lease operating expenses on a per-BOE basis increased from $18.66 per BOE in Q4 to $22.20 per BOE in Q1. The increase on a per BOE basis was due primarily to the impact of asset sales in Q4, approximately $1.82-per-barrel impact, as these assets were weighted toward natural gas and therefore had a lower cost per BOE. As stated in our Q4 conference call, our Q4 pro forma LOE per BOE, excluding these sales, would have put our lease operating expense around $20.50 per BOE. And we anticipated our Q1 cost to be around $20 to $21 per BOE.

Our cost for Q1 ended up higher than this range due primarily to incremental workover costs in our tertiary floods. LOE for our tertiary operations averaged $25.40 per barrel in Q1 as compared to $22.26 per barrel in Q4, due primarily to higher workover cost and slightly lower production. Bob will discuss this in more detail in a few minutes. Going forward, I would expect that our LOE per BOE would be in the $20 to $22 range per BOE, most likely closer to the higher end of the range in Q2 and improving later in the year.

G&A expenses increased from $38.7 million in Q4 to $43.8 million in Q1. As I've stated in our fourth quarter conference call, we did not expect to see any savings related to the sales in Q4 and Q1 expenses are typically higher. The increases that we saw in Q1 related primarily to year-end work and incremental compensation-related items such as payroll taxes, 401(k) match, true-ups to divesting of long-term incentive awards, compensation increases and moving costs. Payroll taxes increased by roughly $3.8 million, primarily related to bonus payments and vesting of long-term incentive awards during the first quarter as nearly all of the company's annual long-term incentives vest in the first quarter. We expect that these costs should return to more normal levels throughout the remainder of the year. Also, our 401(k) match increased approximately $1.5 million from Q4 for the same reason.

We also incurred approximately $1 million to $1.5 million in expenses related to the relocation of our corporate headquarters in Q1. For the remainder of 2011, I would expect that our G&A expense would be at least $5 million lower per quarter and most likely in the range of $36 million to $38 million per quarter with approximately $8.5 million to $9 million of that expense related to stock-based compensation.

Interest expense, net of capitalized interest, decreased sequentially from $52.9 million to $48.8 million. Capitalized interest was approximately $11 million in Q1 as compared to $10.7 million in Q4. Average debt outstanding was $2.5 billion in Q1 as compared to $2.8 billion in Q4, the decrease due primarily to the bank debt of Encore Energy Partners that was transferred in the sale.

Going forward, we expect to see our capitalized interest around $11 million to $13 million per quarter during 2011, increasing slightly throughout the year, but depending upon certain assets replaced in the service.

During the first quarter, we refinanced $525 million of our 7.5% subordinated debt with $400 million of new 6 3/8% subordinated notes due August 2021. We also repaid $125 million of subordinated debt, of which about $55 million was actually paid April 1. As a result, we recorded approximately $16 million in early debt extinguishment, approximately $13 million for the call premium and approximately $3 million in deferred financing costs. This transaction will save us around $13.9 million in annual interest. We have no bank debt outstanding of our $1.6 billion bank credit line and we had $128 million of cash on hand as of March 31.

In light of higher oil prices and projected cash flows, we recently increased our capital spending budget for 2011 from $1.1 billion to $1.3 billion, excluding acquisitions and excluding approximately $100 million in capitalized interest and tertiary startup cost at Hastings and Oyster Bayou Field that we anticipate will be capitalized until production commences from those fields.

Our estimate also assumes a similar level of capital cost carryovers in 2011 as we had in 2010. For 2011, based on current prices, we currently estimate that our projected capital expenditures, including the capitalized interest and other items, will be $100 million to $200 million greater than our estimated cash flow from operations, which should be covered for the most part by our excess cash on hand at the end of 2010.

Our DD&A per BOE increased slightly, $16.35 in Q1 as compared to $15.87 per BOE in Q4, primarily due to capital expenditures in Q1. Due to our book loss in Q1 resulting from noncash hedging losses, we record a current- and deferred-tax benefit for the first quarter. Going forward, I would anticipate our tax rate to be around 38.5% to 39% 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 under which we believe we'll be able to deduct capital expenditures that we would normally have to recoup over time. Now I'll turn it over to Tracy.

Ronald Evans

Thank you, Mark. First, we are pleased to announce the addition of Craig McPherson, who joined us this week as our Senior Vice President of Production Operations and a member of Denbury's Investment Committee. With the growth we have experienced for the past several years and the increasing complexity of our operations, we determined to divide the Senior Vice President of Operations role. Bob has done a tremendous job of leading our operations effort over the past 5 years and should be commended for his dedication and effort. Bob, Senior Vice President of CO2 Operations with his new title, will continue managing our drilling operations, pipeline and CO2-supply operations, Bakken operations, HSE and purchasing functions. Craig will manage our oil and gas operations and our east, west and north operating regions.

Craig comes to Denbury with 30 years of experience with ConocoPhillips, most recently serving as their general manager of the Gulf Coast business unit where he directed all of ConocoPhillips' technical, operational and business activities in the Gulf Coast region. The addition of Craig to our staff and the splitting of responsibilities between Bob and Craig will allow greater focus and attention to all aspects of our operations and will enhance our ability to capitalize on future growth prospects. Welcome, Craig.

As we reported in an earlier press release, we have signed 2 additional anthropogenic CO2 contracts to purchase NYMEX CO2 from existing and planned industrial facilities. Since that time, we have subsequently signed one additional contract in the Gulf Coast. So now 2 of the 3 projects that we've signed CO2 contracts with are in the Gulf Coast and the third is in the Rocky Mountain region. The most recent contract we signed in the Gulf Coast was to purchase 100% of the CO2 captured from a post-combustion CO2-capture project. The project is expected to capture approximately 50 million cubic feet per day of CO2 and could deliver CO2 as early as late 2012 if construction of the capture facility is completed as currently scheduled. The other Gulf Coast project which we previously announced was we expect to purchase about 70% of the CO2 from the Mississippi Power Kemper County IGCC project. This will allow up to about 115 million cubic feet of CO2 per day and, under certain circumstances, we may have to purchase 100% of the CO2 captured from the Mississippi Power project. Mississippi Power has begun construction of the IGCC facility in late 2010 and first deliveries are expected in 2014 for Mississippi Power.

We will not incur any additional capital expenses for construction of the lateral lines on both of the Gulf Coast projects, as both of them will construct the necessary lateral lines to deliver the CO2 into our existing pipeline. Mississippi Power will deliver the CO2 at Heidelberg Field and eventually into the Free State Pipeline, and the other project in the Gulf Coast will deliver the CO2 to Hastings Field via our Green Pipeline Texas.

In the Rocky Mountains, we announced the signing of a contract to purchase 100% of the CO2 from DKRW's planned coal-to-fuels project in Medicine Bow, Wyoming. DKRW currently expects first deliveries of CO2 to begin in late 2014-early 2015. We will construct the necessary pipelines to connect DKRW's facility with our planned Greencore Pipeline in Wyoming. We have initiated a study to determine the optimum route for the pipeline from DKRW to the Greencore Pipeline, but preliminary estimates indicate approximately 120 to 130 miles of pipeline will be necessary. These volumes, coupled with the expected volumes from our Riley Ridge acquisition and our contract for CO2 from Lost Cabin, bring our total contracted or owned CO2 volumes in the Rocky Mountains to almost 400 million cubic feet per day, which is a significant percentage of our expected requirements for the Rocky Mountain region. We continue to work with other potential suppliers of CO2 in the Gulf Coast and in the Rocky Mountains to secure additional volumes of CO2.

We'll switch gears and talk a little bit about Denbury's position in the Tuscaloosa marine shale in Mississippi and Louisiana. We acquired approximately 200,000 acres of leases in Mississippi and Louisiana with short lease expirations through our Encore acquisition. Encore has spent a conservative amount of capital and time testing the Tuscaloosa marine shale, which resulted and the only Tuscaloosa marine shales with continuous production to date. Given our planned activity in our CO2 EOR operations in the Bakken and the relatively short period of time before leases were going to expire, we decided to seek a joint venture partner to continue testing the Tuscaloosa marine shale.

We have entered into an agreement with a joint venture partner covering approximately 100,000 acres of the Tuscaloosa marine shale acreage that had not yet expired. Under this agreement, the joint venture partner provided immediate capital to extend expiring leases, has a right to elect to complete a well that was never completed, drill and complete one additional well, and to carry us in additional leak -- lease acquisitions until such time as an agreed-upon amount of capital is invested. After the joint venture partner has expended the agreed-upon capital by completing the one well, drilling an additional well and/or acquiring additional leases, Denbury will have the opportunity to participate for 15% working interest in all future drilling on a unit-by-unit election. Prior to the expenditures of the agreed-upon capital, Denbury will be carried for a 15% interest in all operations or lease acquisitions. This transaction does not include Denbury's Tuscaloosa marine shale interest under any of our existing CO2 properties in Southwest Mississippi or Louisiana. And with that, I'll turn it over to Bob to talk about operations.

Robert Cornelius

Thank you, Tracy. I'll give you folks a quick update on our major CO2 EOR projects, our Bakken activity and then some pipeline construction progress during the first quarter. As Mark reported, tertiary production averaged 30,825 net BOE during the first quarter. That's approximately flat with fourth quarter production rates as we suggested to you in our last conference call.

During the fourth quarter of 2010, tertiary production rates were led by positive response in both Tinsley and Heidelberg Field as both of these fields responded slightly ahead of schedule. During the first quarter of this year, production from these 2 fields temporarily leveled out for various reasons. As you're aware, production growth rate of EOR field varies from quarter-to-quarter as the EOR field production may increase rapidly when wells respond to CO2 injection, plateau temporarily and then resume the growth profile as additional areas of the field respond. Also during tertiary-flood life cycle, facilities have to be increased from time to time. Facility modifications sometime require temporary shutdowns during the final tie-ins of the equipment, thereby causing brief declines or flattenings of production rates. A planned shutdown occurred at Tinsley in the first quarter. We also find it difficult to precisely predict when any given well will respond to CO2 injection as the CO2 seldom travels through the reservoir rock consistently due to the heterogeneity of the oil-bearing formations. All of these fluctuations are normal and we generally expect oil production in a tertiary field to increase over time until the entire field is developed, albeit sometimes inconsistently. These types of fluctuations are most -- were most noticeable at Tinsley and Heidelberg Fields during the first quarter of 2011. These 2 fields had exhibited strong production growth in recent periods, and we expect our tertiary production to resume its growth later this year as additional wells are placed on production and CO2-recycling facilities are expanded.

Our most mature area, Phase 1 production, decreased approximately 5% quarter-to-quarter with an average daily rate of 12,040 net BOEs during that first quarter. Lockhart Crossing continues to perform well with the first quarter production slightly ahead of the fourth quarter production rate.

Brookhaven Field was flat quarter-to-quarter, but they're slightly negative 35 net BOEs per day average. The reduction driven by well work during -- conforming of 2 injection wells that were converted to WAG. WAG is water alternating gas injection in our 4-pattern program. CO2 injection rate into these existing wells was curtailed into the area while we did the workovers. All these wells have now returned to injection during April and oil rates [ph] are expected to increase in the coming months.

Our most mature floods, Bell Creek, McComb, Smithdale and Mallalieu, all declined slightly quarter-to-quarter. In Southeast Mississippi, Phase 2 experienced a 420 net BOE, a 4% decrease in production rate in the first quarter when compared to the fourth quarter. As previously reported, Heidelberg experienced a significant production increase during the fourth quarter. Production flattened during the first quarter as we begin to work on wells and we saw additional recycle compression. As these wells respond, we should see an increase in production rate during the third and fourth quarters.

Soso Field decreased 247 BOEs per day, primarily due to normal decline in that EOR field. Also, Soso is a mature field and we continue to well work during the quarter to expand 2 new patterns in the Bailey formation. We've got a field with -- essentially flat quarter-to-quarter, producing 3,247 net BOEs during the first quarter. CO2 injection conformance work was performed on several injection wells during the late part of 2010 to improve CO2 distribution throughout the various intervals, helping us minimize any further decline. Martinville declined 86 BOEs and producing average of 500 net BOEs during the quarter.

Tinsley Phase 3 average daily production during the first quarter was flat when compared to the fourth quarter of 2010. It has averaged 6,567 net BOEs per day. During the first quarter, the team conducted a planned shutdown to install increased water-handling equipment and installed additional recycling compression equipment that will be operational during May. These activities were planned and are necessary to prepare the CO2 recyclability for the increased volume of oil, water and CO2 through the end of the year as we add additional wells and infrastructure to the East Fault Block. Tinsley continued to be aggressively developed with capital investment in excess of $50 million as we continue to expand the well work and infrastructure. This East Fault Block is the largest fault block in the field.

Currently, there are 16 wells that should be responding during the next 6 months in Tinsley.

Cranfield Phase 4 produced -- production decreased 51 net BOEs quarter-to-quarter. We expect second quarter production to increase as we made repairs to one of our better wells that was down for several weeks during the first quarter. It is 100-plus barrels per day well, and it was successfully repaired and returned to operation during April and the unit production now has returned to its prior production before that well went down.

Delhi's production averaged 1,524 BOEs per day during the first quarter, which was an increase of 821 BOEs per day or almost a 117% increase quarter-to-quarter. Test Sites 1 and 2 were placed in service during the quarter. At the same time, injection volumes and well count also increased. Delhi team expect an increased production for the remainder of the year.

Hastings Field is now the largest field under CO2 injection. We started CO2 injection during December 2010. The goal is to build reservoir pressure up to a target operating pressure of about 3,000 psi during December. Expansion of fault block A is the focus of our 2011 capital, although regulatory permitting is approved. The CO2 recycle facility is now under construction. We expect the facility to be operational late this year with initial tertiary production either late this year, early next.

Dimensional production averaged 1,160 net BOEs per day, which was a decrease of 314 for the quarter. And some wells were taken off production in preparation for CO2 injection. Primary production expected to continue its normal decline since fault block A wells were taken off-line in late 2010 to prepare for this flood.

At Oyster Bayou, we began injection during June of 2010. We received our core of engineering's [ph] permit to start the CO2 recycle facility at the Oyster Bayou during January, and construction is now underway. First year oil production from the Oyster Bayou Field is expected to occur in about a year from now, and will be dependent on the date of the completion of that recycle field.

Conroe Field, which is still conventional production, was 2,978 net BOEs during the first quarter which was an increase of 213 above the fourth quarter volume. Increase was a result of successful workovers and equipment upgrades taking place during the quarter.

At Jackson Dome, we complete the drilling of the development well and DRI Dock field. The top of the Northlick [ph] pay zone or CO2-bearing sand came in structurally lower than expected. At this time, the results of the various well tests are inconclusive. So as we process that data and review the results, we're going to move our drilling rig to the Gluckstadt Field where we have an opportunity to drill both a rate well and a well that could add significant proved reserves. There's also plans to bring a second drilling rig into the area in the latter part of June or early July to test another geological structure that could help test a portion of our 5.6 Tcf probable and possible CO2 reserves in the area.

Moving to the Rocky Mountain. The team is preparing the Bell Creek Field located at the Southeast Montana for CO2 injection. Idle wells are being worked over and completed for CO2 service. The well work is being completed before the CO2 pipeline is commissioned during the fourth quarter of 2012. The 232 mile 20-inch Greencore Pipeline that will connect the Lost Cabin gas processing facility with Bell Creek Field in Montana is on schedule. The pipeline is being constructed in 2 segments. The first is 115 miles of pipeline, with target construction to begin in August of 2011. The construction will wind down some time during the winter of 2011 and then the final segment is expected to be completed during the fourth quarter of 2012.

Let me switch to the Bakken now. Denbury now operates 5 drilling rigs in the play. We initially expected to complete and bring on 8 wells during the first quarter. Weather and fracturing services slowed down all activities between June and mid-March. We were only able to complete and place 5 wells online during the period, and 3 of the 5 wells were not completed until March. We frac-ed 5 wells in April and 5 additional wells are planned to fracture-treated during May. We now have long-term agreements with 2 service companies for a total of 5 frac days per month to cover off all of our 2011 drilling program.

Now while first quarter Bakken production rates are less than expected, we are leaving our original production forecast unchanged at an average production rate of 8,700 net BOEs per day during 2011. Now to meet that average production rate for the year, we must continue to have completion success and improvement in the weather. But the Bakken team is building on some recent successes. Several completions since last analyst call are the Thompson 31-11 northwest horizontal and the Thompson 31-11 southwest horizontal. Both of these Bakken wells are in the Charlson area. These wells had IPs of 1,605 and 1,501 gross BOEs per day respectively.

In the Cherry area, we completed a Satler [ph] 44, southwest horizontal in the Hoffman 149-98. These 2 wells IP-ed for 2,258 and 1,894 gross BOEs respectively. The Christianson 24-9 northeast horizontal was completed in the Camp/Indian Hill area is still under flowback at a rate in excess of 1,017 gross BOEs per day on a 20 64 choke. The Christianson 24-9 rig is restricted due to oil and water takeaway capacity, so we're still working on those. Today, we had a cleanout of the Satler [ph] 44-34 northwest horizontal. It's in the Cherry area. It's a very strong well, but if we were able to IP it today, it would be also above 2,000 BOEs per day.

We have executed 3 drilling contracts for additional rigs that are expected to start drilling in September, October and December of this year, so we plan to exit the year with about 7 operating rigs in the Bakken.

Lease operating expenses during the first quarter of 2011. Operating cost for tertiary properties averaged $25.40 per BOE, and that's compared to the fourth quarter operating cost of $22.26 barrels -- dollars per BOE. The per barrel increase quarter-to-quarter was primarily due to increases in workover expenses with more minor increases in power and fuel and some new leased equip -- new equipment leases. First quarter of 2011 operating expenses -- workover expenses increased $1.38 per barrel over the fourth quarter of 2011, as we -- what we did is we accelerated some planned wellbore, reworks and repairs in the Brookhaven Field. Rather than perform that work over the entire period, we accelerated into the first quarter. So with that, I'll turn it over to Phil.

Phil Rykhoek

Thanks, guys. That concludes our prepared remarks. So with that, I'll turn it back to Elizabeth for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And first, we'll go to the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

On your budget increase, can you give a little bit of color? Is that all just sort of rig drilling? Or is there any cost inflation included in that as well?

Robert Cornelius

I think there's a little bit of cost inflation in there. We did move from $1 billion to $1.3 billion. We added some projects at Jackson Dome. We added projects in the Bakken. We made some other changes, but yes, we are seeing some slight increases in our capital equipment.

Phil Rykhoek

There were increases kind of everywhere. I mean, I think we accelerated the well at Jackson Dome. We added new rigs, adds a little bit of cost in the Bakken. We are already bumping our cost estimates a little bit there. But it's kind of spread out, trying to also, I think, accelerate even a little bit of the pipeline stuff. I think we put a little bit of money in for Conroe pipeline. So it's just a little bit kind of all across the whole spectrum.

Scott Hanold - RBC Capital Markets, LLC

Okay. And I think you guys had been sort of, kind of in front of potentially seeing higher cost in the Bakken and it's kind of playing also. But you just mentioned you saw these ER cost, the smelter [ph] maybe bumped a little bit more. Where you're looking at for a -- see out there right now?

Robert Cornelius

Right now our EOP [ph] is running at $7.8 million, but we're -- I looked today at some of the wells we've just discussed. And they're probably going to come in around $8.5 million. So we're hoping, we've seen some efficiencies with the weather. We've seen some efficiency with our Bakken team, and we hope to hold the $7.8 million to $8.5 million range.

Scott Hanold - RBC Capital Markets, LLC

Remind me how many fracs does that play.

Phil Rykhoek

I'll give you [ph] 24.

Robert Cornelius

Oh yes, stages, yes, 23 to 24 stages.

Scott Hanold - RBC Capital Markets, LLC

Okay. And you do them planning [ph] first 3 months?

Robert Cornelius

No. [indiscernible] sliding sleeves. Yes, we use mostly sliding sleeve.

Scott Hanold - RBC Capital Markets, LLC

Got you. All right. And on tertiary production, is production being relatively flat for tertiary in 2Q? Am I reading into that right? Or could it be slightly down and then it sounds like it will start accelerating in the back half of the year. Is that a fair statement?

Phil Rykhoek

Q2 should be up slightly. It just won't be a big increase and most of the growth is in the latter part of the year. I think we'll have a slight bump in Q2.

Scott Hanold - RBC Capital Markets, LLC

Okay. And when you look at 3Q and 4Q, what really are the big factors to really get that moving upwards? I mean, is there a couple projects that are really critical?

Ronald Evans

Yes, I mean most of the growth was Heidelberg, Tinsley and Delhi.

Phil Rykhoek

Yes, I mean, Bob mentioned we have a lot of wells that we think are going to respond in Tinsley. They're producing water. We think it's going to turn to oil here shortly, so we expect -- basically, Heidelberg and Tinsley are the 2 that kind of plateau-ed and we expect that growth to resume because we're continuing to expand those floods. Delhi is already doing well and we expect it to continue to grow, but it's been on a pretty good growth path the last several quarters.

Scott Hanold - RBC Capital Markets, LLC

Okay. And then one last thing on the tertiary at Hastings Field. Is there anything you all can see, as you're injecting CO2, that leads you to believe that this may be on time or not? Or is it one of those things where it's just literally wait and see?

Ronald Evans

No, we can monitor the pressure increase obviously as we try to raise the pressure towards the miscibility pressures or at least get it close as we can to miscibility pressure. We can monitor that and we're seeing the pressure rise about as expected as we have with the injection. So we feel very good about it. I really think the issue with Hastings will be facility timing. We hope to get that done very late this year and the other thing is we did shut in production at Hastings. So we expect, as soon as we get the facility completed, to have production.

Scott Hanold - RBC Capital Markets, LLC

And lastly on the Tuscaloosa shale, Tracy, you gave a lot of detail on the JV and maybe for -- can you give a survey, just a higher level view? But it sounds like of the 200,000 acres you have, 100,000 of that is going to be under the JV, and what are going to be your sort of general working interest in that? Because you're going to be a non-operator on there. Is that correct?

Ronald Evans

That's correct. Now the 200,000 is what we had when we acquired it last March. And over the past year, about half of it had gone away. So when we signed the joint venture, it was plus or minus 100,000 acres. So we will have -- at the time of the JV signing, we had 100,000 now. The operator of the JV is leasing up. We know their leasing agent, so we don't know the speed at which they're leasing but they're leasing acreage. So we'll have more a bit later what our eventual position will be. But we're going to have roughly a 15% interest in the play as it develops. Now that excludes the 45,000 or 50,000 acres that we have under our CO2 EOR projects. So, I guess, technically today you could say we have 150,000 acres, 50,000 of which we have virtually 100% in; and 100,000, we would have 15% in.

Scott Hanold - RBC Capital Markets, LLC

Okay. Got it. And is there any reason why the tertiary phase is -- with the tertiary phases over the 50,000. You wouldn't want to be poking holes through that. Or is it just -- you just got to be careful logistically that you don't get in the way of the CO2 stuff?

Robert Cornelius

No, I mean we could. It's just that the results are very, very early in this play. I mean, even some of the comments yesterday -- I've heard several people mentioned it is frontier. So we've got a lot of opportunities to continue our EOR development, and we're just going to watch our JV partner and see if we can -- if they can unlock secrets to the Tuscaloosa marine shale and then when we feel like it's de-risked further that we can look at developing the TMS under our existing CO2 floods.

Operator

Line of Dave Kistler with Simmons Company (sic) [Simmons & Company].

David Kistler - Simmons & Company

Real quickly with the sixth and seventh rigs coming in to the Bakken -- and you mentioned a little bit previously about trucking takeaway capacity, completion services. When you set up your 5 completions per month, does that incorporate ramping up the rig count?

Ronald Evans

We are looking at getting the sixth by the time we ramp up. Remember, towards the end of the year in the fourth quarter, that we were trying to hopefully get a sixth. We're working on that right now. As far as the trucking, we're working on some trucking companies to help us. Rig move, as you know, very critical out there. We're working on that. Also to help us enhance our ability to have 0 flat time or less flat time between completion of the well and spud of the next well. So we're working on that also.

David Kistler - Simmons & Company

And any chance we can get kind of an update on where current production levels are just so we have a sense to how this is trending?

Phil Rykhoek

We would rather not give monthlies or current, but it's trending up.

David Kistler - Simmons & Company

Okay. I appreciate that. And then switching over to the CO2 injection. In the past, you guys have had success implementing WAGs. Obviously, it's been special situations where you've done that. But is there any consideration to doing that at the beginning? And is the reason for not doing it a cost-based decision? I guess one other question on it would be, "If you did a WAG, would it actually reduce your total demand for CO2 in some of these plays?"

Ronald Evans

Yes, if we did WAG, it would reduce the CO2 demand per barrel, if you want to call it that. So that's a factual statement. The modeling we've done on the Gulf Coast fields has indicated that basically by going to continuous or staying with continuous injection, you recover the same amount of oil and at faster period of time and, therefore, you have a higher net present value. The WAGs that we're using -- I mean, they are successful. WAGs have been successful in West Texas for years. But in the Gulf Coast sands, I mean, we are more homogeneous typically and, therefore, our sweep efficiencies are pretty high using just CO2. But we continue to look at that and we'll monitor it. But right now, we're starting everything with continuous injection. And one thing we have done -- it's not technically a WAG, Dave, but one thing we have done is started doing some down dip injection beneath the oil-water contact for 2 reasons: one, that helps raise pressure too; and then secondly, it does contain the CO2 into the -- above the oil-water contact. So we are looking at using water, kind of in a little different method than the traditional WAG. But we continue to look at that and if we see instances where a WAG would make more sense, then we might try it.

David Kistler - Simmons & Company

Okay. That's helpful. One last thing just so I understand a little bit better. Is there a big cost differential for implementing a WAG versus what you're doing on the CO2 side?

Ronald Evans

There might be a little bit. I mean, obviously, you're moving CO2 to an injection line. Either you'd have to have a second injection line or you probably have to modify the existing injection line to handle both water and CO2 in alternating phases. But I don't think that would be significant. I mean, we haven't not done a WAG because of the cost, if that's the question. But right now, with our cost of CO2, it's probably cheaper than water.

David Kistler - Simmons & Company

That's more of what I was getting at. "Is it cheaper on the other side?" not the inverse. Anyway, I appreciate the color.

Operator

[Operator Instructions] Next, we'll go to the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Just a couple things. Looking at what we've seen commodity prices do over the last few months, I just wonder if you have any general thoughts about how you might change your hedging philosophy going forward. We seem to be in an era where downside protection isn't quite so much the worry it was 18 months ago, say.

Phil Rykhoek

I mean, we've kind of followed our policy and we've been doing this, I guess almost 2 years where we've been going kind of 12 to 15 months out. And I think we'll probably stick with that. We did go just a little bit further, probably about 18 to 21. We went through the end of 2012, but that was -- we kind of just took advantage of an uptick in oil price. And as Mark pointed out, we upped the floors to $80 and got ceilings in the upper $120s. But I think on a general basis, we'll try to do this 12- to 15-, 12- to 18-month-type program. It works very well for us because it gives us time to adjust if prices do dip and a lot of our equipment still has a pretty long lead time and so forth. So it gives us time to adjust.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay, great. And, actually, speaking of equipment lead times, as far as just the basic facility upgrades you have to make as you build tertiary production at the various fields, what sort of lead time -- or what sort of planning do you have to have for compressors and so forth at this point?

Robert Cornelius

I mean, Noel, we're pretty fortunate because as we build these things out, we have everything on a schedule. So the compression is probably the longest item, so we already have compression out a year in advance. And we have alliance with our provider. So really on the EOR side, we've not seen any type of tightening of what we need because of the way we order it and because we know our schedules.

Phil Rykhoek

The compression still take about a year.

Robert Cornelius

About a year, yes.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay, great. And Bob, one thing I just wanted to get from you again. Could you just repeat the Delhi production rate number for the quarter again? I just didn't quite get that.

Robert Cornelius

It made 1,520 -- averaged 1,524 barrels oil per day for the first quarter, which was about a 821 BOE increase.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay. And I think -- pretty much the last one I had, you mentioned the development well at DRI Dock. I believe you just said that the structure, I think, was up shift from where you expected. Can you just talk a little bit more about that? Because I don't remember you guys generally haven't too much trouble with the development wells out there usually.

Ronald Evans

We haven't had trouble. It was fairly surprising, we're trying to figure it out with all our diagnostics and reprocessing. But the well came in low. It came in 150 feet lower than we expected. So we're trying to figure out, exactly, did the structure -- well, the structure didn't technically shift, but was our seismic shifted or something like that, that led to us -- ended up being low. So we're going through all that process now and we should have more information later on.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Is it too soon to have a sense as to whether or not the CO2 to resource there is essentially unchanged? Or do you really need to work some more on it first?

Robert Cornelius

It's too early at this point to determine that.

Operator

And next we'll go to the line of Jason Wangler with SunTrust.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Just had one quick one for the sixth and seventh rigs up in the Bakken here in the next couple of months. Have you contracted those yet? Or you're just starting to get those kind of felt out?

Robert Cornelius

No, we've got them under contract. We executed contracts about a month ago...

Ronald Evans

Almost a month ago.

Robert Cornelius

3 weeks ago. So yes, they're on -- we have 3 rigs now under contract.

Phil Rykhoek

[indiscernible] seven, we're going to pop one [ph]. That gets you your seventh.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Perfect. And then for the sixth one going up to Almond. Is the goal there to drill a few wells there and kind of maybe pull that back and get an understanding what you have there, and then decide the development plan, depending on the results?

Robert Cornelius

Yes, that's right. We'll go drill one in Almond and then in northeast Foothills also.

Phil Rykhoek

We have about 65,000 acres in Almond, so we kind of need to test it and see what we want to do there because there's definitely a third time [ph].

Operator

And next, we'll go to the line of Cory Garcia with Raymond James.

Cory J. Garcia

Quick question. I apologize if I missed this, but any updates with regard to potentially barging some of that crude from Tinsley down to get some of the higher-value, seaborne crudes?

Phil Rykhoek

Yes, it's still in progress. I think the weather or something, I forget, has -- the high water on the Mississippi, I believe, has actually slowed it down just a little bit. But I think that's still anticipated in a couple months, 3 months maybe.

Operator

[Operator Instructions] And there are no more questions in queue. Please continue.

Phil Rykhoek

Thanks, everybody. I want to remind you to mark your calendars for our upcoming Spring Analyst Meeting. We're going to start with a breakfast meeting in New York on Monday, May 23, and then we'll have a repeat presentation at Boston the next morning on May 24. That Wednesday and Thursday, Tracy and I plan to be on the West Coast, San Francisco and Los Angeles. And I know some in the Midwest have asked that we come up there, but we'll have to do that on a separate trip, probably later this year. We'll try to make a trip to the Midwest. So mark your calendars. We hope to see you soon. Thank you.

Operator

And ladies and gentlemen, this conference will be made available for replay after 12:30 p.m. today through June 5. You may access the executive replay system at any time by dialing 1 (800) 475-6701 and entering the access code of 189714. International participants may dial (320) 365-3844 with the access code of 189714. That does conclude your conference for today. Thank you for your participation and for using AT&T Executive TeleConference. You may now disconnect.

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