Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Denbury Resources (NYSE:DNR)

Q1 2012 Earnings Call

May 03, 2012 11:00 am ET

Executives

Jack T. Collins - Executive Director of Investor Relations

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

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

Craig John Kenneth McPherson - Senior Vice President of Production Operations

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

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

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

Jeffrey W. Robertson - Barclays Capital, Research Division

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

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

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

Robert Bellinski - Morningstar Inc., Research Division

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

Operator

Ladies and gentlemen, thank you for standing by, and welcome to your conference call today, the first quarter 2012 earnings release. [Operator Instructions] As a reminder, today's call is being recorded.

Your hosting speaker, Executive Director of Investor Relations, Jack Collins. Please go ahead, sir.

Jack T. Collins

Okay. Thank you, Kevin. Good morning, everyone, and thank you for joining us on Denbury's First Quarter 2012 Results Conference Call. With me today on the call are Phil Rykhoek, our President and CEO; Mark Allen, our Senior Vice President and CFO; Craig McPherson, our Senior Vice President of Production Operations; and Bob Cornelius, our Senior Vice President of CO2 Operations. In a moment, I'll turn the call over to Phil and the other members of senior management to discuss our first quarter results and discuss our outlook.

But before that, let me remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause actual results to differ materially from what is discussed. You can read our full disclosure on forward-looking statements and 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.

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

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

Phil Rykhoek

Thanks, Jack. As you can see from our first quarter, we're starting off the year on a positive note. But before I get into the quarterly results, let me briefly talk about the acquisition we announced a couple of days ago. Tuesday, we announced we agreed to acquire Thompson Field for $360 million plus a production payment. This is a significant strategic acquisition for us and exactly the type of deal that we want to do for the following reasons.

First and foremost, Thompson Field is desirable because it's a large field located only 18 miles from the termination of our Green Pipeline, meaning that there will be minimal additional required pipeline infrastructure to plug this field. It's a field technically similar to Hastings, meaning that what we learned at Hastings, we'll easily transfer over. It's a large field with an estimated 650 million barrels of oil in place, and it is one of our top 10 desired fields in the Gulf Coast area. As our review has been rather limited thus far, we've not yet determined how much of the field will be floodable, but we are comfortable saying we can target at least 300 million barrels of original oil in place. That would translate into an EOR target of 30 million to 60 million barrels, or expressed in other way, it's an estimated recovery approximate equal to Tinsley Field. While significant, I believe that with further review, we will add additional floodable areas at Thompson and the projected EOR recoveries should increase. Although initial EOR production is a few years away, this will fit in nicely with our Gulf Coast program, extending our peak EOR production from that area.

In addition to the EOR potential, the acquisition adds a little immediate conventional production in cash flow, adding about 2,200 barrels a day or about the same production that we saw earlier this year. The field has several conventional projects -- development projects that we can do with attractive rates of return. And that should allow us to minimize the conventional production decline. We are fortunate in the timing of this acquisition as we anticipate receiving like-kind exchange treatment, which will save us about $30 million in current taxes, creating additional value for our shareholders. We expect the transition to close in early June, and currently estimate first tertiary production around 2017. The timing reflects the need to unitize the field, construct an 18-mile extension of our CO2 pipeline from Hastings and manage and properly allocate our CO2 supply and transportation. We'll be able to give you more details on this once we have a little more time to study it, create an EOR model and development plan. But bottom line, we're enthused we're able to pick up another significant Gulf Coast oilfield and add to our extensive inventory of the EOR projects.

Briefly on the first quarter. We reported a first quarter adjusted net income of $161 million, $0.41 per diluted share and adjusted cash flow of $352 million. Both of these are slightly less than our last quarter's record-setting levels but still very strong, up 55% and 30% respectively from the year ago. Of course, as Jack mentioned, these are non-GAAP measures. And see our press release and other documents for the reconciling items.

As we announced in our operational update in mid-April, production in oil prices started 2012 on a positive note. As you can see in today's release, our costs were in line with expectations. All of this resulted in a net bottom line that is slightly ahead of Street estimate. Our production, as previously announced, is doing well and we expect to remain in the upper half of our production guidance for 2012. Mark will give you more details, but we decided not to change our overall 2012 production guidance at this time, although we did reallocate a little bit.

Increase in the Bakken number low, and in the Riley Ridge forecast, which is all positive because that's shifting from gas to oil. Since our operations are starting up well as evidenced by our favorable production, costs have remained on target. And a promising oil price outlook, we've increased our 2012 capital budget by $150 million to $1.5 billion. We're adding about $80 million to our Bakken, a portion of which will fund the fourth rig and a portion of which will cover higher than initially anticipated cost. The balance will be used to get a headstart on our planned 2013 expenditures on tertiary floods and CO2 sources. If oil prices hold, these additional expenditures should be funded with operating cash flow.

One of the important thing I'd like to point out in today's release is that we booked approximately 18 million barrels of oil equivalent proved reserves, including 14 million barrels at Oyster Bayou Field, based on this positive response to CO2 injections. Highlighting this value that added to the shareholders, we estimate the PV-10 Value of Oyster Bayou reserves at quarter end were about $510 million or about a 5% increase to our year-end 2011 PV-10 of $10.6 billion. If you look at this on a per share basis, this field added about $1.30 per share to our proved net asset value, a significant addition.

Hastings Field continues to respond well to our CO2 flooding and we expect to booked proved reserves there during the second half of the year. 2012 continues to shape up as a great year for Denbury, we expect our proved net asset value to grow significantly as a result.

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

Mark C. Allen

Thanks, Phil. In my comments I'll provide further analysis of our quarterly results, primarily focusing on the sequential change and results from the fourth quarter of 2011 to the first quarter of 2012. I will also provide some forward-looking information for your financial models.

As reported in our press release, our adjusted net income for the first quarter was $161 million or $0.41 per diluted share. This was down from our record adjusted net income of $175 million in the fourth quarter, primarily due to higher lease operating costs, G&A expense and higher DD&A expense, which I will discuss in more detail. Adjusted net income is a non-GAAP measure that excludes certain items typically excluded by the investment community and published estimates as they are unusual and nonrecurring in nature, which for this quarter, included the following items on an after-tax basis: a noncash fair value hedging loss of $27 million; impairment charges of $9 million, related to our investment in the Faustina gasification project and $1 million its CO2 property; $3 million for CO2 exploration expense for the unsuccessful well we announced earlier this year; $2 million for charges related to anticipated nonperformance on helium deliveries due to delays in the startup of Riley Ridge; $2 million associated with an allowance for loans that we inherited in the Encore acquisition that are tied to future well revenues; and a $1 million loss associated with the sale of our Vanguard units in Q1. I'll provide more color around some of these items later in my comments.

Our adjusted cash flow from operations, which excludes working capital changes, was $352 million for Q1, down from $387 million last quarter, with the difference primarily due to higher operating costs and higher current taxes in the current quarter. Our total production for this quarter was about 71,500 barrels of oil equivalent per day, up 6% sequentially from Q4. If you exclude the property sales we have executed in 2012, our adjusted first quarter production was roughly 69,800 barrels of oil equivalent per day. Craig will go into more detail on our production results, but we are pleased that our tertiary and Bakken production are off to a great start.

As stated in our press release, we have kept our 2012 production estimates unchanged at the range of 68,625 BOE per day to 73,625 BOE per day. But we have bumped our Bakken estimated range by approximately 1,600 BOE per day and lowered our Rockies production estimate by the same amount to reflect the better-than-expected Bakken results, offset by delays in the startup of our Riley Ridge natural gas processing facility. At this point, our guidance does not include the contribution from Thompson Field. Daily net production from this field is currently estimated at approximately 2,200 barrels per day, which is about the same as the assets we sold earlier this year. We will formally adjust our production estimates for the anticipated contribution with this field closer to the time the transaction closes.

Our average realized oil price, excluding derivative settlements, was $102.52 per barrel, down slightly from $103.08 per barrel in Q4. Our average realized oil price relative to the average NYMEX oil price, which we refer to as our NYMEX differential, contracted significantly from Q4, moving to a $0.37 per barrel discount to NYMEX in Q1 as compared to a $9.14 per barrel premium in Q4. For our tertiary oil production, most of which is sold on LLS-based indexes, the average NYMEX price premium was $9.80 this quarter as compared to a $19.44 premium in Q4, with some of our tertiary production receiving premiums to NYMEX north of $12 for this quarter. The LLS to NYMEX premium continues to be volatile in 2012, with the LLS premium rebounding to about $20 in early April, then declining into the mid- to upper-teens currently.

Differentials in our Rocky Mountain properties widened out in the first quarter with our Bakken production averaging a $16.96 discount to NYMEX as compared to an $8.42 discount to NYMEX in Q4. Bakken differentials have recently narrowed to a more historical range, and we currently see them remaining constant or improving in the near term. Based on the fluctuations we are seeing in our NYMEX differentials, we currently anticipate that our overall corporate differential should improve slightly in Q2 from Q1 levels.

Moving on to our hedging activity. We continue to execute a strategy of protecting our oil price downside while retaining upside through costless collars, which sell based on NYMEX oil prices. Since our last call, we have added to our hedge positions for the second half of 2013. Full details of our hedged positions are now -- are shown in our corporate presentation available in the Investor Relations section of our website.

In the first quarter, we paid approximately $8 million on our oil hedge settlements, while we received about $7 million from our gas hedges. Our lowest ceiling price increases to $110 in the second quarter of 2012. And based on current NYMEX Strip prices, we currently do not anticipate significant oil hedge cash payments in Q2 over the remainder of 2012. Our lease operating expense per barrel of oil equivalent increased by 6% from Q4, averaging $29.19 this quarter. For our tertiary operations, this number averaged $26.74 for the quarter. Craig will discuss more on our lease operating expense in a few minutes.

For 2012, we expect our total company LOE per BOE to be in the $20 to $25 range going forward. We expensed $3.1 million after-tax in CO2 discovery or exploration cost in Q1 related to 2012 cost for the CO2 exploration well we announced earlier this year. As a reminder, under accounting rules we are required to expense drilling costs as we incur them on CO2 exploration wells that don't have proved or probable reserves. In the quarter, we also incurred a $9.4 million after-tax impairment charge for our investment in the Faustina gasification plant, a potential source of anthropogenic CO2 in the Gulf Coast, when a key investor and participant in the project indicated they were abandoning it. The Faustina plant was previously listed in our potential anthropogenic CO2 sources, but the potential CO2 from the facility is not necessary to develop our current CO2 projects in the Gulf Coast.

G&A expense was roughly $37 million, which was higher than $28 million in Q4. If you recall, our employee bonus payouts and incentive compensation were paid out at significantly lower percentages last year. And in 2012, we have increased our accrual for such items at a higher level. Also, Q1 tends to have higher professional fees and additional payroll burdens related to bonus payouts, investing of long-term incentives. For the remainder of 2012, we expect our G&A expense to be between $35 million and $40 million for the quarter, and approximately $8 million to $10 million of that expense will be stock-based compensation.

Our overall DD&A rate per BOE increased to $18.57 this quarter as compared to $17.80 in Q4. The increase was principally driven by higher Bakken well costs reflected in our future development costs and incremental depreciation on our CO2 and other fixed assets due to incremental pipeline depreciation. We expect this rate to increase moderately throughout 2012.

Our taxes other income on a per BOE basis increased to $6.71 this quarter as compared to $6.34 in Q4 as higher production and ad valorem taxes pushed this amount higher. As a percentage of our revenues, this expense decreased to about 6.9% as compared to approximately 6.5% in the prior quarter. This category will continue to fluctuate with commodity prices and production. Our effective income tax rate for the quarter was approximately 37%, slightly lower than our estimated 38% statutory tax rate, primarily due to the higher pretax income from the gain on the Vanguard units in January 2012, which allowed us to utilize more preferential tax items. For the remainder of 2012, we anticipate our effective tax rate will be between the 38% and 39% with current taxes representing about 20% of our total taxes.

Moving to our capital structure. Average debt outstanding was $2.7 billion, about $100 million above Q4 2011 level. Interest expense net of capitalized interest increased slightly sequentially to $36.3 million from $35.7 million last quarter. Capitalized interest was $19.4 million as compared to $19.6 million in Q4. We currently expect that our capitalized interest will be between $15 million and $19 million for the quarter for the remainder of 2012. We had $445 million outstanding on our $1.6 billion bank credit facility at the end of the quarter, up from $385 million at year end. However, net of our cash positions, our bank debt was approximately $228 million at the end of Q1 as compared to $366 million at year end. At the end of Q1, our cash balance was approximately $218 million.

We plan to use a portion of the cash realized from the sale of our assets earlier in 2012 and additional borrowings on our credit facility to fund the $360 million Thompson acquisition when it closes. We recently went through our semiannual borrowing base redetermination, and our lenders reaffirmed our borrowing base at $1.6 billion with a potential for that borrowing base to be significantly higher, if needed or if we desired. Our capitalization metrics continue to be very strong and our debt-to-capital ratio at approximately 36% and our debt to Q1 annualized adjusted cash flow and EBITDA at 1.9x and 1.7x, respectively.

If we look back to our analysis of sources and uses of capital for 2012, as we laid out in our analyst meeting last November, our current expectations for sources of cash in 2012 using current strip prices are expected to exceed the high end of the range we set for adjusted cash flows from operations, which was $1.4 billion. And our cash to inflows from asset sales came in at approximately $314 million, which was more than the $300 million high end of the range. With our asset sales complete and cash flow running ahead of original estimates, we are comfortable increasing our capital budget from $1.35 billion to $1.5 billion without incurring significant incremental debt. Also, we have not repurchased any additional stocks since year end under our stock repurchase program.

After considering the Thompson Field purchase and using current strip prices and assuming no incremental stock repurchases, we would project that our bank debt at the end of the year would be around $575 million to $625 million, with the increase from the $385 million at year end 2011, due primarily to the Thompson Field acquisition.

And now I'll turn it over to Craig.

Craig John Kenneth McPherson

Okay. Thanks, Mark. Let me start by saying that our operations ran very well last quarter. When we look at our tertiary operations, tertiary production was 33,257 barrels of oil per day during the first quarter, resulting in 7% growth compared to the fourth quarter of 2011.

There are several key fields that had material impact on the strong first quarter that I'm going to comment on. And I'll start with Tinsley. Tinsley Field production increased by approximately 960 barrels of oil per day compared to the fourth quarter to 7,297 barrels of oil per day. During the quarter, we completed all remediation work on wells in the field that had not been properly plugged and abandoned by prior operators. This allowed us to resume full CO2 injections in the field. The field is responding quicker than originally forecast due to high CO2 injection rates, enabling the reservoir pressure to increase more rapidly back to target. We anticipate additional production growth at Tinsley through mid-year 2012 then relatively flat during the second half of the year.

Delhi. Delhi Field production continues to exceed forecast as the reservoir responds to CO2 injection and we put more wells online. Delhi's average production increased by 400 barrels per day compared to the prior quarter, and we remain very pleased with the field's response to CO2 injection. We'll continue to expand our activities at Delhi throughout 2012.

Heidelberg. Heidelberg tertiary production decreased by approximately 145 barrels of oil per day compared to the fourth quarter. We conducted extensive components work in the West Heidelberg Field during the second half of 2011 to redirect CO2 in the zones previously not injected into. We're seeing strong signs that the conformance performance work was successful. In Q1, production in West Heidelberg has performed better than forecast. However, East Heidelberg production has lagged expectations due to reservoir pressure not increasing as fast as we had forecast. We've taken supplemental action to build pressure in the reservoir, which required some downtime in Q1 to install additional equipment. We expect the pace of production growth at East Heidelberg to increase as the reservoir pressure grows. Our overall expectations for the total Heidelberg area, which includes both East and West, is unchanged as we expect modest production growth in 2012.

Oyster Bayou. Oyster Bayou contributed production for its first full quarter after we started tertiary production in December of 2011. Q1 averaged 877 barrels per day and we anticipate additional production growth in 2012 as we bring on more wells and the wells dewater. Oyster Bayou is expected to have strong growth in 2012 and should reach peak production in the next year or so. To date, it's on track, although we have very high expectations. And it could be tough to fully achieve this year.

Hastings. Production from the Hastings Fields, where we commenced tertiary production in mid-January 2012, averaged 618 barrels per day during the first quarter, and we're very encouraged by the field's early reservoir response. Hastings production is currently exceeding expectations and we expect that to continue throughout 2012. Most of our other tertiary fields not discussed are either flat or on a modest decline, declining about 3% 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 early strong performance in Oyster Bayou, Hastings, Tinsley and Delhi, we anticipate full year tertiary production to be in the upper half of that range. We booked approximately 14 million barrels of proved tertiary reserves at Oyster Bayou in the first quarter and we expect to have proved reserves at Hastings in the second half of the year. Of the incremental $70 million budget increase for tertiary fields and CO2 sources, the majority of that will be spent to accelerate tertiary projects at Hastings and Bell Creek, and that's going to benefit our 2013 production. That concludes my comments on the tertiary fields.

And I'll now move to our Bakken operations. Bakken production increased 29% over fourth quarter rates averaging 15,114 barrels of oil equivalent during the first quarter. Improved completion activity in the Bakken continued during the first quarter as we were able to complete 13 wells during the period. The completion activity, improved efficiencies and good weather resulted in better-than-expected production rates. Also we booked approximately 4 million barrels of additional Bakken proved reserves in the first quarter.

A full summary of recent Bakken well results is available in the corporate presentation posted on our website. Of note was a recently completed Three Forks test in the Cherry area with encouraging initial production over 2,000 barrels of oil per day. Our plans are to drill approximately 17 Three Forks wells during 2012. Our operated well costs have averaged approximately $10.8 million in the first part of the year. Our goal is to get our cost under $10 million per well and we believe this is possible by the increased efficiency that will come from pad drilling, along with our pursuit of opportunities to optimize our drilling and completion practices.

We currently have 5 operated rigs running in the Bakken. We plan to reduce this count to 4 when we allow 1 of the drilling contracts to expire in the next few weeks. Our working rig inventory includes 3 efficient flex drilling rigs. And with these new rigs drilling from multi-well pads, our goal is to reduce the number of days to drill. We have adjusted our capital plans for the Bakken and now plan to keep a fourth rig running for the full year and spend $480 million in the region in 2012, up from $400 million previously announced. The higher capital expenditures will fund the fourth rig in the second half of the year and cover higher-than-forecasted well costs.

Our original budget assumes that we went down to 3 rigs at mid-year, so this represents an increase of a 0.5 rig year. Considering the time lag from drilling to first production, which will be more pronounced with the transition to pad drilling, this additional funding is not expected to materially impact 2012 but will give us a boost going into 2013. We are on track to have our significant leasehold positions held by production during the second quarter. Once leases are held, we'll shift to multi-well pad drilling. As mentioned, our first quarter Bakken production growth was strong.

And although we expect some additional growth in 2012, the growth rate is expected to slow as a result of our gradual reduction in our operated rig count. For our 2012 full year production forecast, we've increased our estimated Bakken production range to between 14,350 and 16,350 barrels of oil per day. Given the strong first quarter performance and keeping the fourth rig at end of the year, we anticipate that we'll be in the upper half of that range.

I'll move now to lease operating expenses. Operating cost for our tertiary properties averaged $26.74 per barrel in Q1. That's a 13% increase compared to $23.59 in the prior quarter. This increase was primarily due to the startup of new fields at Oyster Bayou and Hastings. The tertiary per barrel operating costs are expected to decline in 2012 as production from these new fields increases. Non-tertiary operating costs were down by $0.69 per BOE compared to the fourth quarter of 2011. And that's primarily due to our sale of properties with high operating costs. Total company lease operating cost on a unit basis for the first quarter was $21.19 per barrel as compared to $20.08 per barrel in Q4.

That concludes my remarks. And I'll turn the call over to Bob.

Robert L. Cornelius

Thank you, Craig. And I'll begin my comments by updating you on our activities in the Riley Ridge and in LaBarge Field in Wyoming. Recall that Denbury acquired the Riley Ridge unit and the gas processing facility and became operator in August of 2011, with the purchase of the remaining 57.5% working interest.

Strategically, the acquisition provides CO2 reserves in excess of 2.2 Tcf for our EOR programs in the Rocky Mountain areas. The reservoir also produced helium and natural gas. Now while reviewing and commissioning the various systems at the Riley Ridge gas processing facility, our operations team identified several design modifications to equipment and safety systems that needs to be adjusted. The proposed changes will provide assurance that the plant runs safely and effectively. However, some of the modifications require materials with normal lead times or long order times. And as a result, we now anticipate that the field will start production in the fourth quarter of 2012.

As Mark mentioned in his comments, the delayed startup resulted in an after-tax charge of approximately $2 million related to take-or-pay contracts for the helium we expected to produce from the plant. The construction of additional processing our sweetening facility to separate the CO2 from the remaining natural gas streams and the construction of a CO2 pipeline to our EOR facility remains on track to be completed in approximately 5 years. For the most part, much of the expense of the process in sweetening CO2 will be carried by the sales of helium and the methane.

Now let me give you a quick update on the Greencore pipeline, which is our first CO2 transportation pipeline in the Rocky Mountain. The Greencore pipeline will connect ConocoPhillips' operated Lost Cabin process facility to our Bell Creek Field. Now to complete the second half -- we completed the first half, or 150 miles of the 232-mile line, during 2011. And construction activities are scheduled to resume in August after wildlife stipulations are lifted. This final segment should be completed and commissioned by December of this year. In fact, the first connecting piping from Lost Cabin gas facility to our adjacent compression side is now in progress with compression and metering equipments being installed later this year. So our Rocky Mountain's EOR plans are taking shape and well underway.

Let me move now to Jackson Dome area, where our CO2 production rate averaged over 1 Bcf per day during the quarter. During the first quarter, we drilled a development well in the Gluckstadt Field. The well at the Anderson Estate is being completed and connected to our dehydration system. Once completed in the next 2 weeks, the well should produce approximately 50 million cubic feet a day. Our plans in the Jackson Dome area are to continue to drill the many development opportunities that exist in the area. Our geologic team has identified 33 different drilling opportunities in the Jackson Dome. The locations will be hydrated and drilled to further increase our CO2 production rate during the next few years. Denbury has several additional Tcf of unproven CO2 potential at Jackson Dome. But a proved potential is expected to provide CO2 for future oilfield acquisitions.

As part of our addition to the 2012 capital program, we are drilling another well at Jackson Dome to further increase our supply. Now the second rig is moving to the Jackson Dome area this week. We also are reviewing our long-term capital program at Jackson Dome in order to develop enough CO2 for our newest acquisition, Thompson Field. While this will require some additional drilling at Jackson Dome and/or additional sources of man-made or anthropogenic CO2, we are confident we can develop the incremental CO2 required to this latest acquisition. We continue to pursue various sources of anthropogenic CO2 on our Gulf Coast property. Our extensive CO2 flame activities and pipeline infrastructure in the region provide us a meaningful strategic advantage on this area.

Now fairly quickly on the 2 facilities that are currently under construction in the Gulf Coast region that will provide us anthropogenic CO2. First is Air Products. That's located in Port Arthur. It's a gasifier that is expected to be online the first quarter of 2012. And it's going to provide us approximately 50 million cubic feet a day at Hastings Field. And then Mississippi Power plant, Kemper County, is also on schedule to be completed during 2014 and that should deliver a little over 115 million cubic feet a day or more of CO2 to our Southeast Mississippi fields.

We remain in ongoing discussions with sponsors of numerous other proposed CO2-producing plants that are in and considered along the Gulf Coast area. Our CO2 EOR operation provides a proven method to store man-made CO2. And we continue our efforts to develop anthropogenic CO2 sources to complement our natural sources of CO2.

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

Jack T. Collins

Thanks, Bob. Kevin, can you open the call up for questions?

Question-and-Answer Session

Operator

[Operator Instructions] First question is from the line of Scott Hanold, RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Bob, you sort of addressed some of this, but I'm going to ask the question in different ways. When you look at the acquisition of the Thompson Field, in general, we all think the CO2 -- incremental CO2 needed is, is it like around 0.5 Tcf? And then further that, when you step back and look at Jackson Dome, can you talk about, as you could look forward to potentially acquire more fields and whatnot, how much potential do you think incrementally could be there?

Robert L. Cornelius

Well, we have identified between the Norfolk formation and the [indiscernible] formation, we've identified potential of possible reserves of 7 Tcf of CO2. And remember, Phil said it's going to be 2017. So we feel like we have some time to develop those reserves. We're taking capital investments now in the infrastructure to be able to move that type of reserves through -- or the type of volume through our pipeline systems. And again, we have 5 years to do that, so we're implementing those plans. Phil, as you heard, has got us to drill another well at Jackson Dome. And so we're going to have to modify our drilling program to do this acquisition. But we feel like we can deliver those volumes.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And what kind of incremental deliverability would be just associated with it? And is that sort of 0.5 Tcf of CO2 requirement for development, roughly...

Robert L. Cornelius

I think you're correct. Between 0.5 to 1 Tcf for that field. And if you look at the rate, I mean, it's -- we're at 1.5 -- I mean, 150 million to 200 million cubic feet a day for Oyster Bayou and Hastings.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And then when you look at the end of that field, I know you ought to get out there and do a little bit of work to kind of see what needs to be done. But do you compare and contrast in terms of whether it's been water-flooded. The pressure in the reservoir, is this going to be something that ramps up quickly? Or is it going to be longer? And can you just give us a little bit of color with the understanding how you recognize you've got to kind of get out there and do some work?

Craig John Kenneth McPherson

Well, it's a free reservoir, so it's the same as Hastings. And so we would expect the response to be similar to what we see at Hastings. It has been water-flooded, similar to Hastings. It currently has a higher percentage of oil left in the ground, so we think that's an attractive aspect of the reservoir as well. But in general, we would see it perform quite similarly to Hastings, Oyster Bayou, and frankly, somewhat similar to our Mississippi fields.

Phil Rykhoek

And this is not quite as large as Hastings. Hastings is probably 800 million to 900 million barrels of oil in place. This is 650 million in total. And at this point, we've just identified really about 1/2 of what we think is, at least the initial floodable area. But from a technical standpoint, the characteristics are very, very similar.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So I think you said there's more relative oil in place. Why is that? Has it just not been as -- produces much from a conventional perspective?

Phil Rykhoek

That's correct.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And then moving to the Bakken, can you talk about the type of returns that you think you're seeing right now, the current well costs and where do you think that's going to go? And when you look at your capital decision, how that impacts that?

Phil Rykhoek

Well, as you know, we publish that comparison. Although on a slide show, I think we used $90, and of course oil is closer to $100. So we're probably in the upper 20s, low 30s probably at today's price. Our costs are a little higher than what we're using in that analysis, but we still think we can -- with pad drilling and so forth, we think going forward, we'll still get down in the below 10 or upper 9s. On the well costs, I think that the one we used for the public is $9.6 million. Oil's a little higher, costs are a little higher right at this moment, but we're still pretty optimistic about getting that down.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And approximately how many stages are you using in the average completion on that right now?

Robert L. Cornelius

Well, we're still optimizing that. But in the 20s, upper or mid-20s.

Operator

And next question is from the line of Mike Scialla of Stifel, Nicolaus.

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

You mentioned that Thompson Field, only part of it is floodable at this point. Can you elaborate on what you need to see to determine if more of that is going to be floodable with CO2?

Phil Rykhoek

Well, we, of course, haven't had a chance to really look at it very hard. We know that the field is a bit more faulted than perhaps Hastings or some of our other fields. And so the question is how many of those fault blocks are really practical to flood. Before we bought it, we had the guys do a little bit of a cursory review of it. And they feel very comfortable with what we presented. But that's why I kind of said in my opening remarks, I think that number will grow as we dig into it.

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

Can you even give us a ballpark of what the, say, maximum could be or some kind of upside to the expected number?

Craig John Kenneth McPherson

Well, as mentioned in the press release, we think oil in place is 650 million barrels. We have assumed 300 million barrels as an initial EOR target. All of the 650 million barrels oil in place is a potential EOR target as it has oil in it. And therefore, it can be with CO2 contact we get more oil out. So that's the range of outcomes. We think we're taking a conservative approach in the initial estimate, and the additional scrubbing of the development plan, I think, will prove that more.

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

Great, okay. And you talked about the additional reserves you booked at Oyster Bayou, how about at Heidelberg? I think you'd said, Craig, that your forecast there is unchanged. But in terms of reserve potential, do you see that 31 million of proved and 11 million of 2P and 3P, is that still the right number? Or has that changed?

Craig John Kenneth McPherson

I'm not looking for the numbers -- it's on my fingertips. But in general, our outlook for Heidelberg reserve is unchanged. We're pleased with the conformance work that will access those reserves that are proved. And so we believe we're on track with what we've previously forecast.

Phil Rykhoek

Mike, we didn't make any adjustments through the Heidelberg reserves, nor have we today.

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

So maybe the way to think of it when I'm modeling it is it -- do you still feel like that potential is still there but maybe spread out over a longer time since you're going to be flooding fewer zones at a given time?

Phil Rykhoek

It probably is a little bit more of a modest growth. That would be accurate. Yes.

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

Okay. And then Bob, you mentioned the delay at Riley Ridge. Does that affect the timing of Bell Creek at all?

Robert L. Cornelius

No. Because Bell Creek's initial CO2 is actually coming from Lost Cabin. The ConocoPhillips operated Lost Cabin, and that's on schedule. We are actually making connections from their plant to our compression station during this month. And the pipeline is on schedule. And we should be commissioning it December and injection December, January of next year?

Phil Rykhoek

Yes. Just as a refresher, Cimarex designed this plant and they were going to reinject the CO2, which is what we plan to do initially. So with the initial methane, helium sales, we'll be reinjecting CO2. What we'll do by the time the pipeline gets there in about 5 years is we'll have, I guess, we call it the sweetener plant, but an add-on to the plant that would hold the CO2 out of that stream as we'll use it for EOR.

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

Given where the gas prices are, would there be any reason to -- I mean, how long is that delay going to be in place? And should we expect some more charges going forward for the take-or-pay contract?

Phil Rykhoek

Well, we're anticipating fourth quarter now. And so if we're on track then the charge is probably pretty close. While gas-only sells for a couple of bucks, helium still has a pretty good price, about $70.

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

Okay. Last one for me on the -- you mentioned a good Three Forks well that you've recently completed. Have you tested the lower benches yet in Three Forks? I think you had mentioned you had some plans to do that.

Robert L. Cornelius

No, sir, we have not. There have been no tests. We've only drilled 3, I think, significant tests, so we've not had time to go in and go after the lower benches.

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

Any of the near-term wells plan to test that zone? Or are you going to let other people do that?

Robert L. Cornelius

I think, initially, we're going to let some other people do that.

Craig John Kenneth McPherson

We may cut a core in it, but...

Operator

Next question is from the line of Pearce Hammond of Simmons.

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

At Tinsley, you've had a tremendous amount of success as demonstrated in the quarter, nice production uptick from fourth quarter to first quarter. You elaborated a little bit on Heidelberg and some of the challenges there. What's it going to take to kind of get Heidelberg starting to point in that same kind of direction upward like Tinsley?

Craig John Kenneth McPherson

Well, I will take that in 2 pieces. The Heidelberg reservoir rock is different than Tinsley, so it's going to have a different characteristic. So frankly, the production profile for Tinsley and Heidelberg are going to be a bit different, with Tinsley responding probably quicker and over a shorter time period than Heidelberg. That's really the quick answer. Again, it's going to be in 2 pieces. So West Heidelberg, we're kind of past the peak production profile of West Heidelberg, but we have many, many more years of production out of there. And so we're pleased with how that's going to look, but it's going to be relatively flat for an extended period out of West Heidelberg. East Heidelberg is a new flood. That production profile will increase as it reaches its plateau. So we think there's a nice production and growth component that comes from that as that flood matures over the next year or 2. I hope that provides the color you're looking for.

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

That's great. And then on a housekeeping note, any updates on share repurchases?

Phil Rykhoek

No. I mean, we have not purchased any to date in 2012. So the aggregate is that $195 million that we've purchased in the fourth quarter of '11, just under $14 a share. And I guess, that it's just kind of the standard answer, we have authorized up to $500 million, but we're just kind of watching, being opportunistic and most likely, won't do anything unless we think the stock price slips significantly to low crude NAV.

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

And then on the production guidance, I know it doesn't include the Thompson Field acquisition. But assuming that acquisition does close in early June, will you be revisiting your production guidance at that time?

Phil Rykhoek

It's just hard to do when you don't know the exact date. I mean, we anticipate it would close in early June. But of course, that could slip or be plus or minus a few weeks.

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

Okay. And then last one for me is where are you seeing service costs right now on the Bakken on a leading-edge basis and service availability, as well?

Craig John Kenneth McPherson

Well, the service availability is increasing as more and more crudes go into the basin. So that's good, which has a connection to the cost side, because there's more supply of services. We do see a bit of a softening in the service cost line.

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

Do you have contracts that are coming due later this year that you can take advantage of some of those lower prices?

Craig John Kenneth McPherson

We believe we do have some opportunity to get our contracts into a lower price, yes.

Operator

Next question is from the line of Jeff Robertson, Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Phil, can you all talk a little bit about how Thompson will be slotted into your Gulf Coast EOR project? And will it have any impact on your expectations for the timing of Conroe?

Phil Rykhoek

No. It doesn't affect Conroe. Conroe is scheduled to have a line there by 2014 and initial injection in 2015. At this point in time, we've said probably 2017 or so for Thompson. That timing is, to be fair, is a little soft or actually quite soft perhaps. We know it's going to take us 2 or 3 years unitized and take us 2 or 3 years per line down there. So that's the absolute minimum. But we really need to kind of coordinate this with our supply and get the model built and so forth. So our initial blush is 2017.

Jeffrey W. Robertson - Barclays Capital, Research Division

Since that's so close to Hastings, it will have -- and I guess, a little bit further to the west from Oyster Bayou, it has to be slotted in from a supply standpoint with needs for those fields. Is that right?

Phil Rykhoek

Yes.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. And then is the production that you're buying at Thompson, can you talk about just what kind of profile it's on as you take it over and what it might do for 2000 -- or for the rest of '12 and into '13?

Phil Rykhoek

Well, there are a lot of development projects there. I mean, these are low kind of corner shoot wells and that sort of thing. And the prior owners have done a lot of that. We have several identified. So I think we've said in the release, we may spend $12 million -- $10 million to $12 million a year or so. And if we do that, we think we can hold the production pretty flat. I think there's enough conventional work that we can do that it should have a pretty steady production profile.

Jeffrey W. Robertson - Barclays Capital, Research Division

And then lastly, does the unitization with you, are there other interests that you may be able to acquire or would consider acquiring? Or is that just forming units so you can go from the water flood to a CO2 flood?

Phil Rykhoek

Yes. This is a forming unit. It's next to impossible to do in an EOR flood without unitizing the field because of where the CO2 goes.

Operator

Next question is from the line of the Hsulin Peng, Robert Baird.

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

I'm sorry if I missed this, but I was wondering, which tertiary fields is getting the incremental CapEx in 2012?

Craig John Kenneth McPherson

The tertiary fields are Hastings. We're going to put additional compression at Hastings. And Bell Creek, we're going to put additional facilities in wells there, so hopefully, to accelerate our 2013 production.

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

Right. And then in terms of the -- can you also talk about the potential for booking reserves at the Hastings later in second -- later in 2012?

Phil Rykhoek

Yes. We've kind of talked about this a little bit before, but we expect it to be in the second half of '12, third or fourth quarter. And as you probably know, we tend to book about 75% of what we think the potential is. And so if you kind of translate that to Hastings, it's probably between 40 million and 50 million barrels that we would expect to add some time second half of this year. There's also a little -- a few million barrels are kind of small, but little bit more potential also at Oyster Bayou as the field continues to respond. So the 14 million isn't quite, if you will, 75% of our potential. We kind of book it in pieces here, so there's more upside there.

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

Okay. And then last question, in terms of your Bakken development, can you talk about how much of your Bakken is on pad drilling and how many wells per pad are you targeting right now?

Robert L. Cornelius

What we're doing is we have all the acreage held now. So we're going to put 3 wells per pad. And some of those will be Bakken formation, some of them will be Three Forks. But right now, it's just 3 wells per pad.

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

And that's all you are doing? You're not doing any single well drilling anymore, right?

Robert L. Cornelius

No. That would not be correct. We still have some single wells that we would like to drill, especially when we try to look at the Three Forks. We will probably keep 1 of our rigs doing the 4, doing the single wells and the other 3 will be skid or pad drilling.

Operator

Your next question is from the line of Neal Dingmann of SunTrust.

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

Just to add 2 quick ones. First, just in the Bakken, I was just wondering on when you look at sort of the takeaway, I guess, going forward as you continue to ramp, how you set there and if that had any influence on sort of your thoughts as far as just the going to 4 rigs the rest of the year. Why not with the great results you had there, go back up to a fifth or a sixth rig?

Phil Rykhoek

Well, I guess, the short answer to it is we're just trying to manage our cash flow vis-à-vis debt. And our results, all prices has been strong, production has been strong, et cetera. And so we have a little extra money compared to what we originally forecasted last calls. But we felt like at this point, going to 4 rigs or spending $480 million is all we want to do at this time.

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

Okay. And then just last question just for Bob. Just wondering, again just not being familiar with kind of the delay we saw at Riley Ridge, just your view on this safety review. Is that relatively common, Bob? Is there coming out doing that before these plants?

Robert L. Cornelius

No. Well, a plant of this size, you have a presafety startup review, and our people did that. And so they went through. And what happened is in this particular one, there's materials inside a valve and inside the equipment. And so we have 1 particular valve that the [indiscernible] is not quite right. And so we have to replace that valve stem, even just a part of it. And so that's the long lead item we're looking at. At the same time, we get to go make sure the other processes are operating correctly.

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

I get it. So it's just a long lead item on that one particular that caused a quarter, I guess, or 2 of delay?

Robert L. Cornelius

Yes. That would be correct. And it gives us time to look at other processes and look at the facility. And as Phil pointed out, that at today's gas prices, it's not a big loss of revenue.

Operator

Next question from the line of Andrew Coleman, Raymond James.

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

I just had a question -- I kind of got on the call a little late. But thinking about where Thompson slots in, do you need additional CO2 for that? Or does it -- and I guess, where would it slot in for the -- looking at the estimated EOR peak production schedule you have in your current slide deck?

Phil Rykhoek

Yes. We talked about it a little bit already. But we intentionally -- at least initially expect it to be around 2017 is when we get there and start flooding it. That is to give us time to unitize the field and get pipeline there and so forth. We do need a little bit more CO2 as we probably talked. We're pretty much in balance with our program pre-Thompson and what we have in proved reserves and reserves at Jackson Dome. But if you could go back and look at the notes, Bob pointed out, there's probably 6 or 7 Tcf of probable and possible reserves we still see at Jackson Dome. So we won't need to develop some of those, but we're highly confident that there will be plenty for Thompson. And we just need to kind of schedule that out, schedule the supply and coordination of the CO2 down the pipelines and so forth.

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

Okay. And then thinking about the capital increase there for this year, will there be any additional work at Jackson Dome then as a result?

Phil Rykhoek

We did add 1 additional well we're going to drill at Jackson Dome, so that's about $15 million to $16 million.

Operator

[Operator Instructions] We do have a question in queue from the line of Robert Bellinski, Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

Just wanted to see if there's any interest or opportunity to acquire additional acreage in the Bakken at this point.

Phil Rykhoek

Probably not. We've occasionally picked up some little add-on pieces that's probably not -- was a great asset and we like the value we're creating here. It's probably not something we're really trying to expand or really focus on. Most of the expansion or acquisitions would likely be or almost certainly be EOR candidates.

Robert Bellinski - Morningstar Inc., Research Division

Okay. And then my second question is just want -- it's probably a long shot, but I was wondering if there's any new thoughts or developments in the Tuscaloosa, given the level of exploration activity by other producers in the region.

Craig John Kenneth McPherson

There's really not any new news there. As you know, we have a relationship with EnCana. And so they continue to pursue that. And we hope they're very successful. And we're not participating in some of those wells, we got carried on the first 2 wells. So they continue to drill and we watch the results.

Phil Rykhoek

Our interest is really pretty small, it's 15% of that JV. So plus or minus, what, 15,000 acres net? And so really -- and EnCana is kind of publishing results as they see fit. So I guess, just watch EnCana.

Operator

Your next question is from the line of Noel Parks of Ladenburg.

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

And again, like other people I apologize if you've touched on this already. But the Air Products plant that -- I think the last I heard you guys talk about it was on schedule to go live by the end of the year and hopefully, be delivering -- ready to deliver CO2 by first quarter next year. Do you have -- or I guess, when are we going to be able to hear about sort of the CO2 cost and what the expense -- or how the expenses of building the pipeline are going to get shared and so forth?

Phil Rykhoek

Well, we intentionally try to avoid giving specifics on every little CO2 contract that we have, obviously, because of discussions with other people. What we have stated is that the man made CO2 is going to be more expensive than our natural source. Our natural source is running $0.25, $0.30 out of pocket and maybe $0.10 DD&A, so probably in the $0.30 to $0.40 range. And these man-made sources are kind of in rough numbers, almost 2x, I guess, although they both fluctuate with the price of oil. So they will be a little bit more expensive, but the pipeline itself is very minimal. It's just a few miles off our Green line. So in this case, it's a very minimal cost to connect their products.

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

Has the planning work already begun for that project?

Phil Rykhoek

Yes.

Robert L. Cornelius

Yes. The project is underway. Noel, this is Bob Cornelius. Yes, the project is underway as far as their products. And the planning for the pipeline, yes, it's underway, too.

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

Okay. Great. Do you know when you're going to -- the construction is going to start on that?

Robert L. Cornelius

Well, we should have CO2...

Phil Rykhoek

About a year from now?

Robert L. Cornelius

About a year from now, 2013.

Phil Rykhoek

It won't take a couple of million.

Robert L. Cornelius

It's a small diameter, short line.

Operator

[Operator Instructions] We do have a follow-up actually from the line of Jeff Robertson, Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Well, just real quick, I apologize if I missed this earlier. But you all talked a little earlier about the conformance issues at Heidelberg. Can you just remind me of where you are in that project and where you think production will start getting restored?

Craig John Kenneth McPherson

Well, for the initial phase of the conformance work, it's completed. And we believe the production has been restored. So we're pleased with the production response we're getting. To get a little technical, one of the key measures we watch is the gas flow ratio. And so that's the amount of CO2 that comes out with the barrels of oil. And so one of the keys of success, one of the objectives of conformance, is to get more barrels of oil out per CO2 injected. And we're seeing that happen at Heidelberg. So we believe that the conformance work has been successful, and so production has moderated and their profile looks good. That being said, given the character of the rock at Heidelberg, there's 10 zones, we will always be aggressively addressing and watching conformance. And so that's just an aspect of that field that we'll continue to watch carefully. But we're very pleased with the results to date and encouraged what the future is at Heidelberg, at West Heidelberg.

Operator

At this time, we have no additional questions in queue.

Phil Rykhoek

All right. Well, thanks, everybody, for your attendance and participation today. Just so you're aware, we have a few conferences coming up, one in New York on May 8, one in Chicago in May 10, and then we have our annual meeting here in Dallas on May 15. So 2 or 3 events. We're also planning some investor trips in Canada, the Mid-Atlantic and the West Coast over the next few months. So if you're in one of those areas and want to meet with us, let Jack know and we'll try to get that scheduled. So other than that, our next earnings call will be second quarter results, and that is scheduled for Thursday, August 2.

So thank you much. We look forward to a great 2012, and things are starting off well. We appreciate your attendance today.

Operator

Thank you. Ladies and gentlemen, that does conclude your conference. We do thank you for joining while using the AT&T Executive TeleConference. You may now disconnect. Have a good day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Denbury Resources' CEO Discusses Q1 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts