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Denbury Resources (NYSE:DNR)

Q2 2012 Earnings Call

August 02, 2012 11:00 am ET

Executives

Jack T. Collins - Executive Director of Investor Relations

Phil Rykhoek - Chief Executive Officer, President and Director

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

Craig McPherson - Chief Operating Officer and Senior Vice President

Robert L. Cornelius - Senior Vice President of Co(2) Operations and Assistant Secretary

Analysts

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

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

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

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

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

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

Operator

Good day, ladies and gentlemen, and welcome to the Denbury Resources Second Quarter 2012 Results Conference Call. My name is Kaylee, and I will be your operator for today's call. [Operator Instructions] I would now like to turn the conference over to your host for today's call, Mr. Jack Collins, Denbury's Executive Director of Investor Relations. Please proceed, sir.

Jack T. Collins

Thank you, Kaylee. Good morning, everyone, and thank you for joining us on our second quarter 2012 results conference call. With me today in the room from Denbury are Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; Craig McPherson, our Senior Vice President and Chief Operating Officer; and Bob Cornelius, our Senior Vice President of CO2 operations.

In a moment, I'll turn the call over to Phil and to the other members of senior management to discuss second quarter results and our outlook. Before that, let me remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause actual results to differ materially from what is discussed. You can read our full disclosure on forward-looking statements and the risk factors associated with our business in our corporate presentation, our latest 10-K and today's press release, all of which are posted to our website, www.denbury.com.

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

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

Phil Rykhoek

Thank you, Jack. Before I start reviewing the quarter, I'd like to just express congratulations to 2 members of our senior management team on recent promotions. As we have previously announced, we recently promoted Craig McPherson to Chief Operating Officer. He's done a remarkable for us in the year he's been at Denbury, exceeding expectations and he's playing a key role on taking our operations to a higher level. Craig's on the call with us today, and of course, you'll probably see him on a regular basis in the future.

We also promoted Charlie Gibson to Senior Vice President of Planning, Technology and Business Development. As we continue our growth and expansion in both the Gulf Coast and Rockies, the planning and technology areas are vital to Denbury, and he's -- Charlie has demonstrated his expertise and leadership during the last 10 years at Denbury. And as such, we have placed him over one of the most significant aspects of our business, demonstrating our faith in his abilities. So congratulations to both of them.

Turning to the second quarter, as you saw on this morning's press release, we continue to execute well in 2012. We have growing reserves, growing production, lowering cost and most importantly, creating value for our shareholders. Our tertiary production increased by 6% sequentially as a result of growth from our fields at Hastings and Oyster Bayou and also Tinsley and Heidelberg. Craig will give you much more color on that here in a minute.

Based on the strong tertiary response to date at Hastings, we are able to book initial proved tertiary reserves in this field a bit earlier than we had originally expected. We added about 43 million barrels of oil reserves at Hastings with a PV-10 Value of over $1 billion, and that's using SEC pricing of approximately $95 oil. By itself, that's an incremental value of between $2.50 and $3 per share.

If you recall, we added 14 million barrels of proved tertiary reserves last quarter at Oyster Bayou and that had a PV-10 Value of more than $500 million. So combined, these 2 EOR gives fields gives us nearly 57 million barrels of incremental tertiary oil reserves in the first half of 2012 adding about $4 a share to our PV-10 Value.

At both of these fields, we would expect to add to these proved reserve numbers over time as the fields are further developed. Another point you might make here is that Hastings and Oyster Bayou's positive response to CO2 injections is also very favorable for the recently acquired Thompson. If you recall, Thompson's about 18 miles from Hastings, and the important point is that all 3 fields produce from the same preo [ph] formation.

With reserve additions at Hastings, Oyster Bayou and the Bakken, we've increased our internally estimated proved reserves up 12% from year-end 2011 levels. So bottom line, the tertiary program's doing well, and it's creating real value.

We reported second quarter adjusted net income $138 million, $0.35 a share, adjusted cash flow of $3.62. Both of them ahead of Wall Street consensus estimates. Even though oil prices are lower this quarter than comparative periods, I think it's really neat that adjusted EPS was only down slightly and adjusted cash flow actually increased as the higher production nearly offset the lower prices and cash expenses changed only modestly. Of course, as Jack mentioned, these are non-GAAP measures, so be aware of those differences.

Production growth from our other large asset, the Bakken, slowed significantly this quarter, correlating to a reduction in the rig count. However, we are very pleased our Bakken costs are coming down as expected due to lower service costs and improved efficiencies, and Craig, again, will give you more of the details.

With our high exposure to Gulf Coast oil prices, we continue to realize premium pricing for oil production. For the quarter, our oil differentials improved from a slight negative differential WTI in the first quarter to slightly more than $2 above this quarter, pretty much as expected. With all the talk around NGLs recently, it might be worth noting that we have very little exposure to NGLs as they comprised only about 2.5% of our production in the second quarter. Almost all of that is in the Rockies, and the bulk of that is in Bakken.

Our operating costs per BOE declined on a combination of production growth, sales assets with high op costs and a reclassification of equipment leases, which Mark will give you more color on. With our premium price realizations, our focus on crude oil, a reduction in cost, our operating margins have been one of the highest in the peer group, and we expect this to remain true in the second quarter.

While not all of our peers have reported second quarter results, for those that have our sequential decline in gross operating margin due to the decline in oil prices is the smallest of the group. I think this illustrates an important point, our ability to outperform our peers in a lower price environment even with our generally higher lease operating expenses. We may have some more detail on that at the Intercom Conference here in a couple of weeks.

But in summary, 2012 continues to shape up as a great year for Denbury. We continue to deliver the premium values directly resulting from our unique long-term strategy.

So with that introduction, let's take a look at the details. We'll start with Mark's review of the numbers.

Mark C. Allen

Thanks, Phil. In my comments I'll provide further analysis of our quarterly results, primarily focusing on the sequential change in results from first quarter of 2012. I will also provide some forward-looking guidance for your financial models.

Our adjusted net income, a non-GAAP measure, for the second quarter was $138 million or $0.35 per diluted share. This was down from first quarter adjusted net income of $161 million or $0.41 per diluted share, primarily due to lower oil price realizations and higher DD&A, partially offset by lower lease operating costs and G&A expense. After tax items excluded from adjusted net income in the second quarter included a non-cash fair value hedging gain of $82 million, a $5 million charge related to the change in classification of our equipment leases and $3 million of charges related to the delayed startup of our Riley Ridge facility.

Our adjusted cash flow from operations, which excludes working capital changes, was $362 million for Q2, up slightly from $352 million last quarter, primarily due to lower operating costs and the lower percentage of our taxes being current, which was higher in the prior quarter due to asset sales.

Our continuing total production for the quarter of about 72,280 barrels of oil equivalent per day was up 16% from the prior year period and 4% sequentially.

As indicated in our press release, we are keeping our continuing 2012 production estimates unchanged at the range of 69,350 BOE per day to 74,350 BOE per day, though we continue to anticipate production will be in the upper half of this range.

Our average realized oil price, excluding derivative settlements, was down about $7 from first quarter to about $95.60 per barrel. This decline was less than the decline in the average NYMEX oil price, as we sold our oil at an average price of more than $2 above NYMEX in the second quarter as compared to a nearly $0.40 discount in the first quarter. This improvement was driven by better pricing for our tertiary oil production, which more than offset wider Bakken differentials. All of our tertiary production is in the Gulf Coast region, and the majority of it's sold on the LLS-based indexes.

The average NYMEX price premium for our tertiary production increased by nearly $4 from the first quarter to about $13.60 per barrel, with some of our tertiary production receiving premiums to NYMEX around $19 for this quarter.

Differentials in our Rocky Mountain properties widened out in the second quarter, with our Bakken production averaging more than a $20 discount to NYMEX as compared to a roughly $17 discount in the first quarter. Some of this decline is related to NGL pricing, which lowered our realized price in the Bakken by just under $3 per barrel this quarter as compared to about $2 per barrel last quarter.

Our realized Bakken oil price differentials have been rather volatile this year ranging from the low teens to the mid to upper 20s but generally improving during the second quarter and into the third.

Based on what we have seen in our NYMEX differentials thus far in the third quarter, we currently anticipate that our overall corporate realized oil price should be slightly positive to average NYMEX prices in Q3.

Moving on to our hedging activity. We plan to continue to execute a strategy of protecting our oil price downside while retaining upside through costless collars, which are based on NYMEX oil prices. However, since our last call, we have not added to our hedge positions. But we have -- currently have hedges going through the end of 2013. Full details of our hedge positions are shown in our corporate presentation available in the Investor Relations section of our website.

In the second quarter, we received approximately $8 million from our gas hedges and paid out less than $1 million on our oil hedges. The average floor price for our hedges in the second half of 2012 is $80.

Our lease operating expense was $125 million for the quarter or just under $19 per BOE, down approximately $13 million or over $2 per BOE from the prior quarter. The decrease on a per BOE basis was primarily driven by the increase in production in our tertiary fields, the divestiture of non-core assets with relatively high average unit operating cost and the change in classification of our equipment leases during the quarter.

For our tertiary operations, lease operating expense per BOE averaged $23 for the quarter compared to almost $27 in the first quarter. Craig will discuss our lease operating expense trends in more detail in a few minutes, but let me touch on the impact of the change in classification of our equipment leases.

For some time, we have been entering into sale-leaseback transactions for certain compressors and equipment used in our tertiary operating facilities. During the quarter, we determined that some of the provisions in our lease agreements require that we change our accounting for them to capital leases from operating leases. The classification resulted in the future lease payments coming on to our balance sheet, increasing debt by $164 million and property and equipment by $157 million. This change also reduced second quarter lease operating expense by $8 million, which is offset by an approximate $7 million increase in DD&A and $2 million increase in interest expense.

Although this change has no impact on the expense we would ultimately record, it did result in a onetime incremental after-tax expense of approximately $5 million this quarter. For the remainder of 2012, we expect our total company LOE per BOE to be in the low $20 range.

G&A expense was roughly $35 million, a modest decline from the $37 million in Q1. Of our second quarter G&A expense, about $7 million was stock-based compensation. For the remainder of 2012, we expect G&A expense to be between $35 million and $40 million per quarter, but approximately $7 million to $10 million of that is stock-based compensation.

Our overall DD&A per BOE increased to just over $20 this quarter, an increase of about $1.50 from Q1. This increase was principally driven by the previously mentioned lease reclassification and additional reserves added in the Bakken, which have higher F&D costs than our tertiary operations. We expect DD&A per BOE to increase moderately throughout the remainder of 2012.

Our taxes other than income decreased by about $0.80 per BOE from Q1 to $5.90 this quarter. As a percentage of oil and natural gas revenues, this expense decreased to 6.6% from 6.9% last quarter. This reduction was primarily driven by lower commodity prices.

Our effective income tax rate for the quarter was approximately 38%, in line with our estimated statutory rate. However, current taxes represented less than 1% of taxes in the quarter, which was primarily the result of reduction in oil prices during the second quarter. For the remainder of 2012, we anticipate our effective tax rate will be between 38% and 39%, with current taxes representing approximately 10% to 15% of our total taxes.

Moving to our capital structure. Total debt at June 30 was approximately $3 billion, an approximate $240 million increase from the end of Q1, of which $164 million relates to the reclassification of our equipment leases. We have $520 million drawn on our $1.6 billion bank line at the end of the second quarter.

Based on the results of our semiannual borrowing base redetermination in the spring and additional tertiary reserve bookings since then, we believe we have the ability to significantly increase our $1.6 billion borrowing base if we so desired.

Interest expense net of capitalized interest increased by about $5 million from Q1 to $42 million. The increase was a result of additional borrowing on our credit facility, the equipment lease reclassification and roughly $1 million reduction in capitalized interest due to the startup of new tertiary floods.

Capitalized interest in the quarter was $18 million, and we expect our capitalized interest to be between $15 million and $20 million per quarter for the second half of 2012. Our capitalization metrics remained solid, with our debt-to-capital ratio at approximately 36%, and our debt to Q2 annualized adjusted cash flow and EBITDA at 2x and 1.8x, respectively.

Our 2012 capital budget remains at $1.5 billion, slightly less than half of which has been spent through midyear. Utilizing recent NYMEX oil and gas strip prices and assuming no incremental stock repurchases during 2012, we would project our bank debt to end the year at between $700 million and $800 million.

And now I'll turn it over to Craig.

Craig McPherson

Okay. Thank you, Mark. We'll start with our core tertiary business. Tertiary production was just over 35,200 barrels of oil per day during the second quarter. That's up 6% from the first quarter, with several key sales that had material impacts on the strong second quarter that I'm going to comment on.

We'll start with Tinsley. Tinsley Field production increased by almost 900 barrels of oil per day compared to the first quarter to nearly 8,200 barrels of oil per day. We completed our remediation work in the first quarter on wells in the field that had not been properly plugged and abandoned by prior operators. This makes the second quarter the first full quarter of full strength CO2 injections since remediation work began last year. Tinsley has continued to respond favorably to the high CO2 injection rate, which has enabled the reservoir pressure to increase more rapidly back to target. We expect production at Tinsley to plateau during the back half of 2012. We are developing the north block at Tinsley with an expected production response in 2013.

Moving to Delhi Field. Delhi's production slightly declined in the second quarter to about 4,000 barrels per day. Production has plateaued this past quarter pending the response from the next phase of development. With the water production we're seeing from the newer areas, we do expect production to grow later this year at Delhi.

Heidelberg. Heidelberg Field production increased 240 barrels per day in the second quarter to over 3,800 barrels per day. At West Heidelberg, we continued to see strong signs that our performance work in the second half of 2011 and early 2012 was quite successful. We're also starting to see additional response in the Christianson [ph] in West Heidelberg. Overall, we expect Heidelberg tertiary production to stay relatively flat in the third quarter and then increase in the fourth quarter as additional patterns in East Heidelberg respond.

Moving to Oyster Bayou. Oyster Bayou production increased nearly 430 barrels per day in the second quarter to about 1,300 barrels per day, primarily due to more wells being brought online during the quarter. We're pleased with the early results of Oyster Bayou. While not conclusive, we feel it appears to be acting like a miscible flood with a better-than-expected sweep of the reservoir. This is a good outcome. Characteristics of the early response imply that CO2's contacting more reservoir rocks earlier than we had forecast. Since the CO2 will contact oil that travels through a larger amount of rock, it's going to take a bit longer to reach a producing well than we originally predicted. So the pace of Oyster Bayou's 2012 production growth may not be quite as deep as we had originally forecast, but the implications of this on long-term performance of Oyster Bayou is encouraging. We still expect Oyster Bayou to show strong production growth through the year and expect deep production over the next 12 to 18 months.

Hastings. Hastings production increased by about 1,300 barrels per day to over 1,900 barrels per day in the second quarter. Hastings production exceeded expectation as the field responded quite well to CO2 injection. We expect production to grow into the third quarter and then moderate as we reach the capacity of our recycle compression. Additional compression is anticipated at year end, which should further this production as we go into 2013. Most of our other tertiary fields not discussed are either flat or on a modest decline, declining about 4% in the aggregate on a sequential quarter basis.

For our full year production guidance for 2012, we're keeping our tertiary production unchanged at 33,000 to 36,000 barrels per day. Given the strong performance to date, we continue to anticipate full year tertiary production to be in the upper half of that range.

With that, I'll move on to our Bakken operations. While Bakken production has nearly doubled year-over-year, as anticipated, production improved only slightly in the quarter over Q1 level, at just over 15,200 barrels of oil equivalent per day. Our rate of quarterly production growth in the Bakken slowed, as we reduced our operated rig count in the area to 4 from a peak of 7 last year.

On the operated side, 4 fewer wells came online in Q2 versus Q1, which slowed the production growth rate. The quarter was also impacted by completion operation difficulties on 3 operated wells, which accounted for approximately 500 barrels of oil per day of lost production in the quarter. We anticipate production to increase modestly in the third quarter as several joint pads come online.

Our operated well costs have averaged approximately $10.5 million per well in the first half of 2012. Our most recent wells are at or slightly under $10 million per well because we realized the increased efficiency from pad drilling along with optimization of our drilling and completion practices and service contracts. For 2012 full year production forecast, we've kept out estimated Bakken production range unchanged at 14,350 to 16,350 barrels per day.

With that, I'll move to lease operating expenses. Our tertiary operating expenses declined by about $3.80 per barrel from the first quarter, with about 2/3 of that decline related to the equipment lease reclassifications Mark discussed and the remainder primarily due to start-up cost associated with getting Oyster Bayou and Hastings online in the first quarter, as well as increased production in the second quarter.

Non-tertiary operating costs were down by about $1.30 per BOE compared to Q1 primarily due to the sale of properties with high operating costs. Total company lease operating costs declined by about $2 per barrel from the first quarter to about $19 per barrel with about half of that reduction coming from the operating lease reclassification.

Lastly, I'll review our internally estimated midyear proved reserves. Our total proved reserves as of June 30 were internally estimated to be about 516 million barrels of oil equivalent. That consists of 418 million barrels of oil condensate and natural gas liquids and 588 Bcf of natural gas.

Total reserves added during the first half of 2012 were about 85 million barrels of oil equivalent before dispositions of 13 million barrels of oil equivalent. The majority of our reserve additions were in our tertiary assets where we added about 57 million barrels of oil reserves. As Phil mentioned, our tertiary oil reserves added during the first 6 months were primarily our initial bookings at Hastings and Oyster Bayou of about 43 million barrels and 14 million barrels of oil, respectively.

We've also added 16 million barrels of oil equivalent in the Bakken and about 12 million barrels of proved oil reserves from the Thompson acquisition.

That concludes my remarks, and I'll turn it over to Bob.

Robert L. Cornelius

Thank you, Craig. I'll begin my comments by updating you on our activities at Riley Ridge and the LaBarge Field in Wyoming.

As mentioned on last quarter's call, the startup of the Riley Ridge gas process utilities has been delayed. We have to implement safety modifications to the initial design. Now these modifications are going to ensure that the facility is safe and operated more efficiently. We currently anticipate the facility to be completed by late 2012, with first production expected in early 2013. As Mark mentioned, we recognized another charge in the second quarter related to the construction delay, which increased our accrual for not delivering helium under a take-or-pay contract to the annual maximum of $8 million.

We currently plan to complete the construction of a sweetening plant at Riley Ridge to separate CO2 from the gas stream along with a pipeline to connect this sweetening field to our Rocky Mountain field in approximately 5 years.

Let me give you a quick update on the Greencore pipeline, which is a CO2 pipeline we are to build in the Rocky Mountains to connect our source of CO2 at ConocoPhillips Lost Cabin processing facility to our Bell Creek oilfield.

Recall, we completed the first half of the 232-mile pipeline during 2011 construction season. So we have all the necessary permits and approvals and all received, and our 2012 construction season commenced on August 1. The construction of the remaining half of the pipeline will be completed in early December. So at the Lost Cabin gas facility, which is our source of CO2, our construction work is on target, and we are currently installing the 3 compressors and electrical substation required to compress the CO2 for the pipeline. Pumps and meter equipment will be installed later this year.

So activity at the Bell Creek Field, the EOR field, is also on track to take the CO2 injections that will be delivered in early 2013.

Finally for the Rocky Mountains, at Grieve Field we recently received final approval from the BLM to allow construction of the 3-mile, 8-inch pipeline to the field and estimates occurred during September, early October.

So with the expected start of CO2 injections to Grieve Field during the fourth quarter of 2012, the Greencore pipeline completion and the start of CO2 injections into the Bell Creek Field in early 2013, we can confidently say that our Rocky Mountain EOR plants are gathering shape, and we also gathering momentum.

Now I'll move to the Gulf Coast area, in the Jackson Dome. During the second quarter, we produced an average of just under 1 Bcf per day of CO2. During the quarter, we also contracted a second drilling rig in Jackson Dome area, as we continue to develop our CO2 resources for the Gulf Coast area.

We also completed the Anderson 25-16 #1 that was built in the first quarter. The well tested approximately 70 million cubic feet per day and has averaged over 50 million cubic feet per day right now. Our plans at Jackson Dome are to keep the drilling rig running continuously in the area to evaluate the many opportunities our geological team has identified.

The wells we are drilling in 2012 are primarily rate [ph] wells. So it is unlikely that we will have additional reserve bookings at Jackson Dome during 2012. We also continue to pursue various sources of anthropogenic or man-made CO2 in the Gulf Coast. Our extensive CO2 flooding activities and the pipeline infrastructure in the region provide us a meaningful strategic advantage in the area. Construction of 2 Gulf Coast facilities from which we are -- have agreed to purchase anthropogenic CO2 appear to be on track. We expect Air Products' Steam Methane Reformer in Port Arthur to be online in the first quarter of 2013 and provide approximately 50 million cubic feet a day to our Texas tertiary operations. We expect Mississippi Power Plant to be completed during 2014 and provide approximately 115 million cubic feet per day of CO2 to our Southeast Mississippi tertiary field operations.

We are also pursuing various ways to add anthropogenic sources to complement our natural sources of CO2, and we are now ongoing discussions with various sponsors of numerous other proposed plants that are being constructed along the Gulf Coast area. Our extensive Gulf Coast tertiary operations provide a proven method to store or sequester CO2 while boosting domestic oil production.

So with that I'll turn it over to Jack.

Jack T. Collins

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

Question-and-Answer Session

Operator

[Operator Instructions] Our first question will come from the line of Mike Scialla with Stifel, Nicolaus.

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

On your tertiary oil guidance, you said you'd be toward the high end of the range there. It looks like if you continue to grow at the same rate you did in the first half, you'd be above the high end. Craig, given what you said about what's going on with the various fields, what would you need to see to change that, to push that guidance up a little bit more?

Craig McPherson

Well, maybe just for clarity. So I said we will be in the upper range, so what that means is we will be between the midpoint and the upper number. Where we end up is going to depend on the pace at which Oyster Bayou, Hastings, Heidelberg and Delhi respond over the next 6 months. So really it's -- we're watching those fields. As we mentioned, we're very pleased with how they're performing, but there is uncertainty on a month-by-month basis on how they're going to respond further. So we're just acknowledging that uncertainty in that range. So while it's possible we can be on the high end of that range, it's not a slam dunk. And we really just need to watch the performance of those fields over the next 6 months.

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

Okay, that's fair. Can you say where the tertiary production is now? Or maybe what you saw in July?

Phil Rykhoek

No.

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

I thought that might be the answer. For Thompson Field, on your last call, you said you needed to do some more work to see how much of that field would be floodable. Is -- do you have any better sense now on Thompson Field?

Phil Rykhoek

No. I don't -- we're still looking at it. I don't think we have anything at this point to change anything we've said. Well, I think we'll just stay with what we've previously stated.

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

Okay. And in terms of your -- the proved reserves that you booked for Hastings, I think you typically book about 75% of the potential that you see in these fields. Looks like you booked a little bit less than that at Hastings. Is that because it's a bigger field? And do you anticipate booking any more proved reserves there by the end of this year?

Phil Rykhoek

We might get some minor adds, but it isn't too far off, the 75%. If you look at the range -- well, we've been giving a range on it. But in our slideshow, I believe the low end of the range is 60, so 75% of that will be 45. It was a couple of million barrels off, but it was very, very close to that range, 75% estimate. So it's pretty much on track. On both Hastings and Oyster Bayou, we do expect to add reserves in the future. Maybe you get some small bumps by year end, but I think it will be more likely over time as the field responds and we can justify it.

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

Okay. And then on your well costs in the Bakken, I think you were targeting below $10 million. It sounds like it's crept up a little bit. Yet I hear that everybody's seeing more service availability there. Do you anticipate that, that will translate into lower well costs in the second half? Or where do you stand there now in terms of sort of the midrange for a 20-frac-stage well?

Craig McPherson

Yes. So maybe for clarity, our Bakken well costs have come down significantly. So last year, we were over $11 million a well. In the first half, we've averaged about $10.5 million. Our current costs are coming at or below $10 million per well, and we still see room for improvements. So we've seen a steady significant decrease in our Bakken D&C cost. So we're actually quite pleased with where we are with that trend and really still pursuing additional cost savings that we believe we will be below $10 million.

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

Got it. And how do the economics there now stack up to your CO2 plays?

Phil Rykhoek

Well you've seen our slides, so we've kind of consistently stated that we think that our EOR probably is giving us better returns than the Bakken, and I think we'd still be there. Obviously it helps to lower costs. That's a big factor. And of course, the other part of the factor is we just get a lot better pricing for our oil on EOR than we do at the Bakken. But we would still be -- we would still see returns in EOR quite a bit better than Bakken as far as rate of return.

Operator

We'll go next to the line of Neal Dingmann with SunTrust Robinson Humphrey.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Just a quick follow-up on the Bakken. On the well cost coming down, is it besides efficiencies? Or I know a lot of people earlier had a number of fracs and different things that were already contracted. Now do you have any longer-term contracts that are expiring that can make cost come down? Or is it more just efficiencies that will continue to push the cost down?

Craig McPherson

It's primarily efficiencies that results from moving to pad drilling, but also we've really improved our efficiency, in particular, just we call it avoiding shell strikes, that not hitting shells that require us to do additional work on the well. So that's improved greatly. We have renegotiated some of our service contracts, and so that's starting to manifest itself in the cost. We continue to have those discussions with our service providers. I don't know that we have a big contract that's upcoming that's going to have a sizable shift with our -- its expiry. Really for us, there is no magic bullet. We look at every piece of the puzzle related to our drilling and completion costs and want to be excellent at each one of them. And so that really is what's driving our cost reduction.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And do you anticipate going after some Three Forks in different benches there or will you leave that to others for now and just kind of continue as you've been drilling?

Craig McPherson

Well we are drilling the Three Forks extension and most of our wells for the latter part of this year.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay, and then -- okay, I'm sorry?

Phil Rykhoek

Well, we haven't really tested the second or third. So we'll [indiscernible] ...

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

That was what I was getting at I guess.

Phil Rykhoek

We're watching the industry on that I guess.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just lastly, over -- you mentioned the Jackson Dome, I think, adding that rig that it -- because of the type of drilling that you're doing over, it won't add to the reserves. With that second rig though, what can we expect? A bit of an increase just on the production side with the -- because the CO2 for the remainder of the year? And then would -- is there idea of maybe adding a third rig over there?

Robert L. Cornelius

Well, what we're really doing is we're building CO2 volumes for next year and for the future. So that's first and foremost. It takes a while to get it and get them online, so it's really in 2013 that you'll see the CO2 really increased. And then we don't -- we also are gaining efficiencies on our drilling in the Jackson Dome area, and so we've done that, too. So I don't think you'll see us go above a 2-rig program into the future. And let's make that clear. I want to just make sure -- it's because we think we can get to the volumes that are required with the existing wells that we have scheduled to be drilled.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay, that's fair. And then just lastly, Phil, you all have been pretty disappointed on the hedging strategy. Will you kind of continue just as far as percentage going forward given the, I guess, continued commodity volatility out there?

Phil Rykhoek

Yes. We're trying -- well, I guess, our philosophy is to try to hedge to 12 to 18 months out. And as you've noted, we have hedges all the way through the end of '13. So we'll continue with that philosophical concept, I guess. We do try to be opportunistic though and to put layer in more hedges when prices are high and kind of watch it when prices come down a little. So that's one reason we haven't put any in place the last month or 2 is oil has been a little bit weaker. So we're patient. We're -- we think we're very well protected through the end of '13, so we'll kind of watch for maybe an uptick in prices and layer on some more.

Operator

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

Could you talk a little bit about some of the constraints you're seeing in Hastings? What's going on there? And what's the bottleneck? And then what sort of production rate does it get constrained?

Craig McPherson

Well, the Hastings production is going to be limited by our recycle compression capacity, and so we've actually added some additional capacity this year. So as I mentioned in my comments, we'll reach that capacity probably in the third to fourth quarter. So that will limit the production growth until we add additional compression. That additional compression is anticipated to be added in the fourth quarter, and that will put a boost in production into 2013. It's really about compression capacity. We're very pleased with how the reservoir's responding in sort of early stages.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And so when you add that, is it going to ramp up pretty smoothly into it? Or is it a little bit more like jagged that it's kind of jump a little bit quicker?

Craig McPherson

Well, it'll probably be -- there'll probably a step function when we first add the compression, and then we'll see kind of steady growth from there.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And moving into the Rockies with Bell Creek, could you remind me again. So I think you're targeting first production 2013, and so will injection happen very late this year, early into next year? Is that, again, still the timing?

Robert L. Cornelius

The injection is going to happen early next year. We have to complete the pipeline, and we have to get Lost Cabin on, and that will be probably early next year, start injections.

Phil Rykhoek

And it takes, what, 30 to 45 days to throw the line or 60 days?

Craig McPherson

Yes, that's one of the differences we see with -- between Jackson Dome, where you have a Bcf versus 50 million cubic feet a day. It takes a while to fill 232 miles of 20-inch pipe. It's going to take about 45 days to fill it.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Okay. And so that fill starts sometime in early 2013. And then do you think it's going to be the typical kind of 6 to 9 months before you start seeing some response? Or is it a little bit more unknown in this area?

Phil Rykhoek

There's always some variability but we would anticipate production in late '13.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And then Heidelberg and Tinsley, it sounds like the remediations are pretty much done and it appears successful. Is that a fair statement? Or do we still need to see a little bit more performance into the end of the year?

Craig McPherson

No, that's a very fair statement. We're very pleased with the conformance work done in Heidelberg, on conformance. We continue to monitor that very closely. Pleased with how that looks. And at Tinsley, recovery as evidenced by the increase in production is in good shape.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So all the remediation work at this point is completed. Is that right?

Craig McPherson

That is correct.

Operator

We'll go next to the line of Pearce Hammond with Simmons.

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

Phil, what's your view on Bakken oil differentials really to the end of the year?

Phil Rykhoek

Well, that's a tough one because it's been pretty volatile, and it seems to change quickly. We've seen maybe a little bit of an improvement. Well, second quarter was kind of tough, and it was largely around March and April. But -- so we've seen improvement a little bit. But it's a little hard to forecast. I guess, we tend to kind of look at more long-term trends, and I think it's probably in the low to mid-teens. But it can move around on very minor events because capacity, as you know, there is not a lot of excess capacity.

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

And then staying in the Bakken and we were talking earlier on the call about the potential on the second and the third benches, Three Forks. Would that prospectivity be to your Cherry area potentially?

Phil Rykhoek

Yes. I mean, we were -- there have been a few wells drilled there, and people are finding oil. We just really have not done anything ourselves as far as testing that. So we have plenty of good prospects to do, so we're trying to drill some of the better areas. With prices in the 80s instead of 100, we're trying to, obviously, maximize our returns, so we'll let someone else do some of the experimentation.

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

And then lastly, as you look out at some of these big new pet-chem projects which should be coming on in the Gulf Coast in the latter part of the decade to take advantage of lower natural gas prices, how could Denbury benefit from that? Because I understand that those particular projects in order to secure an air permit have to have a CO2 solution.

Robert L. Cornelius

Well we are talking with all of them. As you know, Denbury has quite a reputation for CO2, CO2 inject, and we have the sequestration project that we have going on at Hastings once their products comes online. So I think that we're a leader. We have a pipeline system. And so we're talking to many of those because they want to locate or co-locate next to our pipeline systems.

Phil Rykhoek

We have a steady stream of people talking to us about different ideas. It's always hard to forecast which ones are actually going to get built and which ones are just ideas, and that's the hard part. But I think just because of our presence in the Gulf Coast, our pipeline infrastructure, we have 16 floods being flooded and so forth, we are always a little bit of a strategic advantage for those guys because they want to make sure that you can take the CO2 every day of the year. So that's our strategic advantage. Forecasting which projects get built and when they'll come on is a little tough. We have only really publicly counted on 2 of them, and that's the Mississippi Power Plant that's under construction and the Air Products addition to the Primero refinery that is also well underway. So those, we feel pretty confident about.

Operator

Our next question will come from the line of Hsulin Peng with Robert W. Baird.

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

So my first question is regarding the Bakken production profile. I was -- can you comment on how we should think about the second half Bakken production? Should it -- will it be -- will it stay around the 15,200 BOE sort of level? Or will it plateau at a -- is it higher? And then how should we think about that going to 2013?

Craig McPherson

As I mentioned, I'm not going to give the exact numbers on Bakken's forecast. But we do expect in the third quarter for production to increase modestly and then probably moderate in the fourth quarter. That's probably the level of detail we're going to give at this point.

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

Okay. No, that's fine. Sounds good. And then second question is regarding just kind of your overall sort of strategy. You guys seem pretty good about spending within your cash flow and just given the recent volatility in oil price. In the scenario where oil price is to decline, can you talk about the flexibility that you have with your CapEx budgets? How do you rank, I mean, in terms tertiary projects or Bakken projects? How do you think about that?

Phil Rykhoek

Well, in fact, I might encourage you to check out our slide presentation because we have a whole page on that. We actually think we're very well positioned in a lower-price environment. One is, if need be, you can -- well, one, our Bakken production is for -- the acreage, for the most part is held so that gives us a lot of flexibility up there. And we kind of use the Bakken a little bit of a swing area for CapEx. So if prices come down further or whatever going into '13, I would expect us to spend less money in the Bakken. It's generally a little bit lower rate of return and that's one of the areas we would probably slow down a bit. But it's nice that we have the flexibility. EOR, you have a lot of flexibility too, if it comes to that. And we -- probably in priorities, we would probably try to preserve our Gulf Coast EOR program because that's our best way to return projects. And if we cut something, it would probably likely be Bakken and/or slowdown the north EOR program a little bit, not Bell Creek and Grieve because they are well underway but maybe some of the other future expansions. So we're still playing it a little bit by ear. We haven't come up with a 2013 budget, but most likely we will try to make that budget pretty close to projected cash flow, at least at that point in time. We know we are spending a little bit more than cash flow in 2012. As Mark indicated, I think he said bank debt should probably be between $700 million, $800 million. So I don't expect any changes for the rest of '12, kind of regardless of what happens. We also have floors at 80, so there's kind of a lower limit as to where our prices can go. But going forward, we would try to spend within cash flow. And I think the swing areas would probably be the Bakken and potentially, some of the expansion in the north EOR.

Operator

We'll go next to the line of Jason Wangler with Wunderlich Securities.

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

Just had one question. As we start looking harder at getting Bell Creek and the other fields up north, what's the oil pricing situation up there? Because obviously down in the Gulf Coast, it's a great spot and the Bakken, obviously, not so much. What does it look like as far as Bell Creek and the other places as we start to get that production next year?

Phil Rykhoek

Well Bell Creek and CCA have generally had better pricing than the Bakken. They are below WTI, but they generally run between 5 and 10 below, whereas the Bakken, it is probably on average 10 to 15 below. Although there are swings in both cases. So I don't know if I know enough to explain why, but they generally have just gotten a little bit better pricing than the Bakken albeit, but not as strong as the Gulf Coast. The Gulf coast is still a lot of LLS pricing. And so in the Gulf Coast, particularly our EOR floods have been running well above NYMEX.

Operator

And we'll go next to the line of Andrew Coleman with Raymond James.

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

Could you just run through, I guess, the number of patterns that you have. And I guess, if you can say the level of -- amount you're injecting into Oyster Bayou, Tinsley and Hastings?

Craig McPherson

I don't know if I've got that off the top of my head. I could get back with you with the details on that.

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

Okay. Yes. I was just curious how that's going to change as you get the new compression on in Hastings later in the year and just the expansion plans are up for 2013. The second question I had was then, I guess, looking at capitalized interest. Will that taper once Bell Creek starts? Or will it taper once you get the Greencore pipeline construction finished?

Phil Rykhoek

Part of it -- partially, we have Riley Ridge, so when that's finished or completed near the end of the year, that will have an impact. Bell Creek will remain capitalized until that comes on production most likely or reserves are booked. And some of the pipeline may remain -- we'll probably see separately once we go with an operation, but there's maybe part of that, that continues to be capitalized.

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

Okay. And then the last question -- and then I'll follow up offline for that -- the pattern data -- was as you look at the Air Products coming on, will -- are the lines from that facility to the fields you're going to use it for or the Green pipeline already in place? And secondarily, are the lines directly to the field? Or are the -- are you going to spike that into the pipeline and then into your EOR fields?

Robert L. Cornelius

Well, the pipeline to connect Air Products to the Green pipe is not in place. But we are getting the right of ways and we're getting engineering done. So our expectations are to have that [indiscernible] they're ready.

Phil Rykhoek

It's a very short line.

Robert L. Cornelius

Yes. It's very short.

Phil Rykhoek

And it would just feed the Green pipeline and then -- but for now it's going to 2 fields, Oyster Bayou and Hastings. Over time, that will get allocated as EBIT.

Operator

[Operator Instructions] We'll go to the line of Noel Parks at Ladenburg Thalmann.

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

Just a couple of things. I also got on a little bit late. As far as the development plan at Hastings, I can't remember exactly how many sort of different phases you had the field divided into. But how far along are you in terms of progressing through the areas of the field?

Craig McPherson

Well we're just at the beginning. So we've got multiple years of development that will be on the level of activities that we've had for the past year. So we just march through Hastings phase to phase at about the same pace that we had over the past 12 to 18 months.

Phil Rykhoek

This is, what, 6- to 8-year development plan. So it's on track as far as pace of development, but it's a multiyear process.

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

Okay. And as you -- I'm just curious as I think about sort of where the projects that as of last year's Analyst Day and you're continuing to build out, out there. How has the labor cost component been as you've been moving forward out there?

Phil Rykhoek

Well I guess I'm not sure of the context of the question completely. I mean, our labor generally is tough. I mean, it's -- the oil business is very competitive, and we've seen -- I don't know. I guess, we're probably running, on average, maybe a 5% inflation factor, but it varies depending on the discipline and some of the professional disciplines are -- it's very much of a bidding war, and so that's just a constant battle that we have in attracting and retaining employees. We have done pretty well, I believe, in that regard. Our turnover rate is actually probably low compared to our peers. I think it's because we -- because of our strategy and obviously, we try to make it a great work environment. But that is a constant issue with us, is compensation.

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

Got you. And just one other thing. If I remember right, was it the East Hastings part of the field where you were interested in ultimately expanding, but I think you didn't have much of an interest over there yet. Are you -- is that a focus in terms of sort of moving forward on the land side there?

Craig McPherson

We are not going to give a whole lot of detail about the land strategy, but East Hastings is still prospected to us, and we're considering that as prospective development further once we finish with West Hastings, which is going to keep us busy for a long time.

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

Sure. Sure. And then just one last thing. I heard -- I can't remember which operator it was, but I heard some rumbling starting of doing some testing of EOR up in the Bakken. I just wondered if you had been in on that or approached by any of the folks up there because of your expertise in that.

Craig McPherson

We are aware of the study work that's going on. We're talking with them about that, but that would be the extent of it. We have no plans to do EOR flooding off Bakken at this point. There's a lot of oil to recover from primaries at this point.

Phil Rykhoek

Yes, we will -- while it may be possible, we've always kind of felt like it's going to be more efficient, more economical to flood some of these big, old oil fields. So that's our first priority.

Operator

Thank you. We have no further questions in queue. So I will turn it back to Mr. Rykhoek for any closing remarks.

Phil Rykhoek

Okay. Thanks, everybody, for your attendance and participation. Just usually I kind of conclude with upcoming events, so I just want to make you aware of those. Several members of the senior management and I will be at Intercom in a couple of weeks, Tuesday, August 14, in Denver. We will be hosting a dinner at the conference the evening of Monday, August 13. So if you're interested in that, contact Jack and there will be several managers -- senior management there if you want to ask questions. Also looking a little bit further ahead, Craig and I will be presenting at the Barclays CEO Conference. That is on Tuesday, September 4, in New York. And we're still debating, but we'll probably stay on the East Coast there potentially for a few days and try to talk with several people. Both of these presentations will be webcast. Slides will be available. And as those, lastly, third quarter -- third quarter 2012 results will be on Tuesday, November 6. So those are kind of the upcoming events. Thank you, everybody, for your attendance today. We look forward to a great 2012. Thank you.

Operator

Thank you, and ladies and gentlemen, today's conference will be available for replay after 12:30 p.m. Central Time today, running through September 2 at midnight. You may access the AT&T Teleconference replay system at any time by dialing 1 (800) 475-6701 and entering the access code of 220095. International participants may dial (320) 365-3844. 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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