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

Denbury Resources (NYSE:DNR)

Q3 2011 Earnings Call

November 03, 2011 11:00 am ET

Executives

Kenneth Craig McPherson - Senior Vice President of Production Operations

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

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

Analysts

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Jeffrey W. Robertson - Barclays Capital, Research Division

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

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

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Gray Peckham - Susquehanna Financial Group, LLLP, Research Division

David W. Kistler - Simmons & Company International, Research Division

Operator

Welcome to the Denbury Resources Inc. Third Quarter 2011 Earnings Conference Call. Today's call is being recorded. Joining us today will be Phil Rykhoek, President and Chief Executive Officer; Mark Allen, Senior Vice President and Chief Financial Officer; Robert Cornelius, Senior Vice President of CO2 Operations; and Craig McPherson, Senior Vice President of the Production Operations.

At this time, for opening remarks and introductions, I will turn the call over to Denbury's Chief Executive Officer, Phil Rykhoek.

Phil Rykhoek

Thank you, Christina. I should remind listeners that today's comments may include forward-looking statements consisting of opinions, forecasts, projections and so forth that are not historical facts. They're based on current assumptions, estimates and projections, but subject to risks and uncertainties that are detailed in our SEC reports, so we encourage you to review those in our SEC document.

Christina already introduced the people that we have on the call. They're senior team here at Denbury. So we'll just jump right into the results.

Our bottom line results this quarter were at record levels for the second straight quarter, in spite of a drop in average NYMEX oil prices of nearly $13 a barrel between the second and third quarters of 2011. Adjusted net income was $148.2 million, up slightly from the $146.7 million in the second quarter. Adjusted cash flow was $357.7 million, up slightly from the $344.1 million recorded in Q2. Of course, the reported book year operating results are quite different with the reconciling items in the noncash, nonrecurring items.

Part of our positive results were due to the improving NYMEX WTI oil differentials, with our net oil price that we received, a little bit over $2.50 a barrel sequentially compared to WTI but even more importantly, up more than $11 a barrel from a year ago if you're looking at the differentials between NYMEX and our net price. So the way you interpret that is if you see $90 on the screen, that is effectively equivalent to over $100 a barrel on a net realized price basis compared with our historical differentials just a year ago.

The LLS differentials continue to expand during the quarter, and we continue to improve our contractual prices, and we are currently selling about 62% of our crude on a contractual basis other than WTI. Our production grew approximately 3% sequentially, generally on track with the prior guidance for 2011, and although Mark will give you more detail, we also showed improvement in many of our expenses when you compare the sequential quarters, all of which contribute to the improved income and cash flow. I might I also remind you that we continue to have over 90% of our production from crude oil, making us one of the highest oil weighted companies.

In summary, I think you'll find this quarter's results to be on track or slightly better than expected. In addition to the positive quarterly results, we're happy to report a 12% quarterly increase in our crude oil and gas reserves, which now stand at approximately 460 million BOE, and we added just over 300 Bcf to our proved CO2 reserves at Jackson Dome, and Bob will give you more details on that.

I'd also like to point out the results to date with our share repurchase program. As of October 31, we have repurchased approximately 3% of the company at a cost of around $150 million, average price of $13.58 per share. This may be one of the most accretive $150 million we have spent in recent history and means that we have improved all of our per share metrics going forward by approximately 3%. Described a different way, we have purchased just under 2,000 barrels a day or $150 million, a great price today for oil production.

Further, all purchases of the share price were below our estimate of proved net asset value at current oil prices. Our repurchase program continues on autopilot until after the Analyst Meeting as a result of a 10b5 plan we enacted last month, and in going forward, we will consider the purchase for stock up to the $500 limit when Denbury is -- when legally Denbury is trading below our proved net asset value.

Today, we'll give you more detail in the second quarter results, but we are going to more discussing 2012. We plan to cover our 2012 plans in detail on our forthcoming Analyst Meeting in just a little bit over a week on Monday, November 14. At that time, we will release 2012 production and CapEx guidance and provide a more thorough update on all of our activities.

So with that introduction, let's take a look at the details for our quarter, and we'll start with Mark's review of the numbers.

Mark C. Allen

Thanks, Phil. As Phil mentioned, Denbury achieved record profitability levels again this quarter in both income and adjusted cash flows. For the next few minutes, I'll provide further analysis of our third quarter results, primarily focusing on the sequential results of the third and second quarters of 2011, and I will also provide some forward-looking information for your projections.

As reported in our press release, Denbury's adjusted net income for the third quarter was $148.2 million or $0.37 per basic common and diluted share, slightly more than our adjusted net income of $146.7 million or $0.37 per share in the second quarter. Adjusted net income is a non-GAAP measure that excludes certain items such as fair value hedging gains and losses and other unusual or nonrecurring items. We believe this is a better reflection of our ongoing period-to-period results. A reconciliation to get from adjusted net income to our reported net income on a GAAP basis of $275.7 million or $0.69 per basic common share is included in our press release.

In the third quarter, we had fair value hedging gain of $205.6 million due primarily to lower NYMEX oil futures prices at the end of September. Our cash flow from operations before working capital changes increased to $357.7 million this quarter, up from $344.1 million last quarter, another company record.

Our total company production for this quarter was 66,830 barrels of oil equivalent per day, up 3% from last quarter's production. Our tertiary production averaged 31,091 barrels per day, up 1% from last quarter's tertiary production, and our Bakken production averaged 9,976 BOE per day, up 31% from last quarter's Bakken production. Craig and Bob will go into more detail on our production results in a few minutes.

Our average realized oil price, excluding derivative settlements, was $96.85 per barrel this quarter as compared to $106.30 per barrel in Q2. Crude oil derivative contracts reduced our net oil price by $0.33 per barrel this quarter as compared to $3.13 per barrel in Q2. On a total company basis, our NYMEX WTI oil price differential continued its positive trend, increasing to $7.25 per barrel above NYMEX this quarter as compared to $3.72 per barrel above NYMEX in Q2. For our tertiary oil production, the average NYMEX price differential was $14.84 per barrel this quarter as compared to $9.69 per barrel above NYMEX in Q2, with some of our tertiary production receiving average positive NYMEX differentials of nearly $20 for this quarter.

Differentials in our Northern properties also improved with our Bakken production averaging $5.62 per barrel below NYMEX, an improvement of $4 per barrel from the NYMEX differential in Q2.

We continue to see the Light Louisiana Sweet oil price trading at a significant premium to the WTI NYMEX oil price. However, recently, we have seen some reduction in LLS versus NYMEX differential. We have shifted as much oil production to the LLS market as possible, with roughly 42% of our oil production now marketed at an oil price that incorporates LLS pricing. We currently anticipate that our company-wide NYMEX differential should remain strong in Q4. However, it is uncertain how long the Gulf Coast differentials will remain at historic highs that the positive LLS to NYMEX differential has recently pulled back from the high 20s to the high teens.

Our hedging positions for Q4 2011 and 2012 have remained unchanged since Q2, but we have added additional hedges for the first quarter of 2013. Thus far, we have hedged roughly 70% of our anticipated oil production for the first quarter of 2013 with collars that have a full price of $70 per barrel and a weighted average cap of near $110 per barrel. We paid approximately $2 million on our oil hedge settlements this quarter, while cash settlements in our gas hedges provided us $6 million.

Our lease operating expense per BOE was up 1% over last quarter, averaging $22.21 per BOE this quarter and $21.99 per BOE last quarter. The increase was primarily due to higher costs on our tertiary operations, offset by the impact of our growing Bakken production, which has a lower per BOE production cost than our tertiary operations. LOE for our tertiary operations averaged $25.34 per barrel this quarter as compared to $23.35 per barrel in Q2, due primarily to higher workover costs. Looking forward to Q4, I would expect our total company LOE per BOE would remain around levels similar to this quarter and the $22-plus per BOE range.

G&A expenses decreased from $30.9 million in Q2 to $28.9 million this quarter. The decrease in this quarter's G&A was primarily attributable to a reduction in bonus accrual, offset in part by increases in other compensation costs, including compensation related to Mr. Evans' resignation and a reduction in office rent due to the termination of legacy Encore office space.

For the fourth quarter of 2011, I would expect that our G&A expense will be in the range of $34 million to $36 million, with approximately $9 million to $10 million of that expense related to stock-based compensation.

Interest expense net of capitalized interest decreased sequentially from $42.2 million last quarter to $37.6 million this quarter, with the decrease due primarily to additional capitalized interest in this quarter. Capitalized interest was $17.9 million this quarter as compared to $13.2 million in Q2. Average debt outstanding was $2.4 billion this quarter as compared to $2.3 billion in Q2, with the increase due primarily to higher bank debt associated with our Riley Ridge acquisition in Q3. We currently expect that our capitalized interest will be around $18 million to $20 million in the fourth quarter of 2011.

We had $110 million outstanding on our $1.6 billion bank credit line at the end of the quarter. As of the end of October, our bank borrowings were $350 million, and net borrowings were approximately $270 million after considering our cash on hand. Before considering the impact from stock repurchases, we were estimating to end the year with somewhere around $225 million to $250 million drawn on our bank line depending on many things, including the timing of capital expenditures, cash flows and working capital requirements. As Phil mentioned, we have purchased approximately $150 million in Denbury stock through October 31 under our share repurchase program, which is authorized to purchase up to $500 million. For 2011, our capital budget remains at $1.35 billion, which excludes approximately $100 million of estimated expenditures for capitalized interest and tertiary startup costs and assumes approximately $60 million in expenditures financed with operating leases. We currently estimate that our projected capital expenditures, including capitalized interest and tertiary startup costs, will be $150 million to $250 million greater than our estimated cash flow from operations, which should be covered for the most part by our excess cash we had on hand at the end of 2010. Therefore, estimated borrowings on our bank line before stock repurchases would essentially be related to our acquisitions during 2011.

Our metrics continue to be very strong, with our debt-to-capital ratio at approximately 33% and our debt to Q3 annualized adjusted cash flow at approximately 1.7x.

Our DD&A per BOE decreased to $16.59 per BOE this quarter as compared to $17.52 per BOE in Q2. This decrease is primarily due to the incremental reserves from the Riley Ridge acquisition. I will anticipate that this rate will increase somewhat in Q4.

Our effective income tax rate was slightly less than our 38% statutory tax rate for the third quarter due to benefits previously unrecognized. In addition, we had a net benefit to current income taxes due to a change in tax treatment for certain items, which resulted in the reclassification of approximately $15 million from current to deferred taxes in the current period. For Q4, I anticipate that our tax credit will be slightly higher than our 38% statutory rate with current taxes in the range of 5% to 10%, assuming we are able to take advantage of certain deductions under the new tax law, which we believe we will be able to deduct most capital expenditures which we would normally have to recoup over time. Most of our current taxes are associated with state taxes at this time.

One last item I would like to mention is that we currently anticipate that we will incur $9 million to $12 million in CO2 exploration expense during the fourth quarter related to the drilling of an exploration well at Jackson Dome. As you may recall, we cannot apply oil and gas accounting rules to our CO2-related expenditures, and therefore, these costs will be expensed even if the well is successful.

Our upcoming Analyst Meeting will provide more information on our projections for 2012, and now I'll turn it over to Craig.

Kenneth Craig McPherson

Okay, thank you, Mark. I'm going to provide an overview of our CO2 EOR production operations for the last quarter. Tertiary production averaged 31,091 barrels of oil per day during the third quarter. This is an increase of 320 barrels of oil per day compared to tertiary production in the second quarter of 2011. Compared to the third quarter of 2010, tertiary production has increased by 1,560 barrels per day, which is a 5% increase. The high-level summary of our third quarter tertiary production compared to second quarter is that our mature field decline was more than offset by significant increases in Delhi and improvement at Cranfield.

In our most mature operating area, Phase 1, production decreased by approximately 5% quarter-to-quarter to an average rate of 10,534 barrels of oil per day. As mentioned in the second quarter call, in general, Phase 1 is entering the decline portion of its life. Production from Phase 1 is expected to decline with quarter-to-quarter fluctuations as we do conformance work and other optimization activities.

Phase 2. Phase 2's production averaged 8,910 barrels per day, just a drop of 485 barrels per day compared to the second quarter. This represents a 5% decline. The West Heidelberg Field was shut in for a few days during the quarter for maintenance and repairs. The conformance work at West Heidelberg Field, which we mentioned in the second quarter conference call, continues. By year-end 2011, we expect to have drilled 3 new wells and modified the injection or production profile on 39 wells to redirect CO2 into previously unswept intervals in Heidelberg.

Additionally, tertiary production began at East Heidelberg late in the third quarter although we're early in the response, we're very pleased with this initial performance. Overall, production from the combined Heidelberg Fields will grow modestly into 2012 with fluctuations from quarter-to-quarter.

Phase 3. Tinsley Field's production in the third quarter was 7,075 barrels per day. This is an increase of 85 barrels a day compared to the second quarter of 2011. As we were expanding the CO2 sled into new patterns in the Tinsley Field, we found that several oil fields -- I'm sorry, several old wells dating back to the 1940s and '50s have been improperly plugged and abandoned by prior operators. The old wells, which were reported as having been plugged and abandoned by the previous operators, did not have sufficient cement in the old wellbores. Without the cement plugs in place, we were unable to confine the CO2 injection into the specific target zones, so we have to stop injecting CO2 into several patterns, reduce the reservoir pressure in those patterns and work over 13 wells to properly plug them.

Additionally, we are in the process of locating and checking 45 additional old wells, which were plugged and abandoned by prior operators, to determine if they were properly plugged. We anticipate completing the needed well work and restarting injection in impacted patterns in the fourth quarter of 2011. Reducing the CO2 injection has lowered our previously anticipated production growth from Tinsley this year and pushed back anticipated 2012 production growth. This has not changed our overall expectations of recovery for Tinsley. In fact, we were starting to see a very nice production response from the new patterns when this issue with the old P&A-d wells occurred.

Moving to Phase 4. Cranfield's production increased to 1,214 barrels per day, which is a 12% increase as additional wells responded to CO2. In Phase 5, Delhi continues to enjoy a faster-than-anticipated production increase as the reservoir response to CO2 injection and we've put more wells online. Production increased by 1,095 barrels per day, which is a 48% increase compared to the previous quarter. We are very pleased with Delhi's response and expansion on that field continues.

With that, I'll move to our future CO2 fields, Phase 7. We started injecting CO2 in the Hastings Field in December of 2010. The goal was to build reservoir pressure up to our target operating pressure by our planned startup date. CO2 injection is on schedule and reservoir pressure continues to increase. Our facility construction has slipped by about a month due to equipment delivery delays and will now likely be ready to start up in late January 2012.

In Phase 8, which is Oyster Bayou, we began injecting CO2 during June of 2010. CO2 injection and the expected reservoir pressure increases are ahead of schedule. Also, we're very pleased with the construction progress. With that, the possibility exists of an earlier-than-scheduled startup. Startup could be as early as January of 2012. If Oyster Bayou continues on its ahead-schedule pace, both the Hastings and Oyster Bayou Fields could be really turn on essentially at the same time. If so, we may change the order and start up Oyster Bayou Field first, followed by Hastings. We expect initial production rate from the Oyster Bayou Field to ramp up faster than Hastings, so turning on Oyster Bayou first will maximize our 2012 production.

Move to Phase 9. Conroe's conventional production was 2,800 barrels a day in the third quarter, which is relatively unchanged from the second quarter, and our other non-tertiary production, excluding Bakken, experienced modest declines during the quarter.

Regarding lease operating costs during the third quarter of 2011, operating costs for our tertiary properties averaged $25.34 per barrel, which compares to our second quarter 2011 average of $23.35 a barrel. Tertiary operating costs were up approximately $7 million compared to the second quarter. This is due to about $3 million in increased costs related to the repair and performance work at Heidelberg Field and some of the well work at Tinsley. We also had spending increases in labor and equipment rental. The non-tertiary operating costs were flat compared to the second quarter of 2011, and then looking at the total company, lease operating costs on a unit basis for the third quarter, they were $22.21 a barrel.

That completes our tertiary production operations overview for the third quarter. Just mentioning our full year forecast, our outlook for the full year 2011 production is unchanged from the guidance provided at last quarter's call of 31,000 barrels per day tertiary production and 65,600 barrels per day for the total company production.

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

Robert L. Cornelius

Thank you, Craig. I'll discuss our third quarter Bakken activity, the Riley Ridge acquisition and then report on the major pipelines and CO2 supply projects.

Improved drilling and completion activity in the Bakken continued during the third quarter as we ramped up from 5 drilling rigs to 7 working rigs during the period. The drilling activity resulted in improved production rates and additional proved reserves during the fourth quarter for our Bakken production.

Our Bakken team continues to introduce improvements in the drilling and completion process as well as overall well operation. Operational advancements are evident in several areas. Drilling times, the number of completions and initial and sustainable production rates continue to see improvement. Improvement, of course, are measures to results. We saw Bakken production rates increase during the third quarter, with production average 9,976 net BOEs quarter-to-quarter. That's a 31% increase over the second quarter Bakken production rates. Drilling time measures from spud dates to spud release also improved from the first quarter to the second quarter and again, from the second quarter to the third quarter. We saw an average of 59 days for the long laterals during the winter months during the first quarter. That reduced to an average rate, day rate of 40 drilling days during the second quarter, dropping again to an average of 33 days during the third quarter.

Denbury contracted 3 new high flex -- 3 rigs. These are now working in the basin. With these new drilling rigs, our goal is to continue to shave off the number of days to drill and the rig moves.

We drilled a test well in the Almond area during October. After logging, we found the Almond area's new Bakken had oil saturations lower than other productive Bakken areas. This logging and petrophysical analysis indicated a noncommercial completion. This is coupled with the poor result of other Bakken -- Almond area wells. We decided to cancel that second well in the Almond. So our Almond area consists of about 65,000 acres, which means we hold an excess of approximately 200,000 acres when you exclude that Almond acreage. Adjusting the Almond area possible and probable reserves, Denbury's total Bakken 3P reserves will still be in excess of approximately 300 million barrels of oil.

Completion processes and results continue to improve during the third quarter, again, measuring these results against prior period. The average initial potentials from our completion were just over 2,197 BOEs per day during the third quarter, that compared to an average initial potential of 1,496 BOEs per day from the wells completed during the second quarter.

Several recent IPs in the Cherry area were the wells 13-24, which are IP-ed at 2,414 BOEs per day and it rolls on 11-16 northeast horizontal, which had initial potential of 2,694 BOEs per day. For a complete list of Bakken completions, please see our web page where we listed every well completed this year.

With the improved initial rates, our current completion schedules and fair weather conditions, we are forecasting that we will meet our 2011 forecast guidance with an average production rate for the year of 8,440 BOEs per day, exiting the year with an average net production rate in excess of 11,000 net BOEs per day. So with successful drilling and completion in the Cherry area and other Bakken areas we had reserve at, we were able to book 11.6 million barrels of proved reserves in the Bakken this quarter.

As we move forward in the Bakken, the 2012 capital budget dollars will determine how many rigs will run going forward, and we'll have more detail on that at our 2012 capital -- at forthcoming Analyst Meeting.

Moving to Riley Ridge, Wyoming. As we reported last quarter, Denbury completed the acquisition of the remaining 57.5% working interest and 9,700-acre Riley Ridge unit, and we also acquired a 33% working interest and additional 28,000 acres adjoining Riley Ridge. Denbury assumes operator share for both projects on August 1.

Strategically, the Riley Ridge unit will provide us with approximately 435 net Bcf of natural gas, 15.5 Bcf of helium and more importantly, approximately 2.4 Tcf of CO2, net Denbury's interest. The first production of natural gas and helium from Riley Ridge is expected to begin late in the first quarter of 2012. This is a little later than we initially expected to their plant startup. Initial production of CO2 is expected in approximately 5 years following construction of additional processing facilities to separate the CO2 from the remaining natural gas stream and the construction of a CO2 pipe to those -- to our EOR field. For the most part, much of this expense of processing the CO2 will be carried by the sale of the helium and the methane.

With the adjusted 28,000 operated acreage acquired, we have also a 33% working interest, and so those net interest is expected to contain probable reserves of 250 to 300 Bcf of natural gas, 9.5 to 11.5 Bcf of helium and 2 to 2.2 Tcf of proved CO2 reserves, net Denbury's interest. Of those -- the development of these reserves are 7 to 8 years out. The adjoining acreage becomes strategic to us, which Phil likes to call it our Jackson Dome with the Rocky Mountains. In some way, the Riley Ridge area may be even better than Jackson Dome as the medicine [ph] reservoir in the Riley Ridge area probably has more CO2 reserves greater than Jackson Dome, and we have the projected methane and helium sales to cover the cost of that development of CO2.

I want to move to pipeline construction. In the Rocky Mountain area, we are starting construction of the 232-mile, 20-inch Greencore Pipeline that connects ConocoPhillips' operated Lost Cabin processing facility to our Bell Creek Field in Montana. Construction started during the latter part of August, with work continuing through November or until winter probably shuts us down. The CO2 pipeline construction is in Natrona, Johnson and the Southern Campbell counties. The pipeline will be constructed in 2 building seasons. The 114 miles of pipeline is targeted to have a completion date of some time November 2011 or until winter, and then the final segments will be expected to be completed during the fourth quarter of 2012. We expect the pipeline to be commissioned and placed in service some time late 2012 or early 2013.

I'll move to the Jackson Dome area where our CO2 daily production rates averaged over 1 Bcf during the quarter. During the quarter, we also finished drilling and completing the Anderson 1-2 well, which should be placed online some time this week or early next. Preliminary estimates indicate additional gross proved reserves of approximately 310 Bcf from this well. Two drilling rigs are currently working in the Jackson Dome area. One well is drilling in the Gluckstadt Field. We anticipate this well will be completed some time during the first quarter of 2012, and this will allow us to increase the CO2 production rates to many of our fields. The second well in the Jackson Dome area we're currently drilling is on a separate geological structure that could prove up a portion of the 5.6 Tcf of probable and possible of CO2 reserves located in the Jackson Dome area.

On our reserve bookings during the quarter, our total proved hydrocarbon reserves as of September 30, 2011, are estimated to be 463 million BOEs. That has a PV-10 value of $10.3 billion for those reserves based on the average first-day month price for the proceeding 12 months. This compares to a second quarter PV-10 value of $9.3 billion and a year-end 2012 PV-10 value of $7.3 billion. So after accounting for production during the first 9 months, we have added 83 million barrels of equivalent. The reserve additions are primarily in the Bakken and related to Riley Ridge acquisition with minimal changes to our EOR reserves. With the production prices used in third quarter, estimates were $94.50 per barrel and $4.23 per MMBtu compared to $79.43 per barrel and $4.45 per MMBtu gas at year end.

For the quarter third quarter, the largest reserve adds were the 39.5 million barrels at Riley Ridge, which was a Cimarex acquisition and then, of course, 11.6 million barrels we added at the Bakken.

One last thing, we continue to monitor status of our CO2 capture projects in which we have purchased contracts. We have Mississippi Power. Mississippi Power continues to make progress in their construction of their Kemper County plant and with expected first deliveries in 2014, and Air Products is making progress in advancing their capture activities with first delivery some time in 2013.

With that, I will turn it over to Phil.

Phil Rykhoek

Okay, thanks, guys. That concludes our prepared remarks. So Christina, can you come back on, and let's take some Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] First question comes from the line of Andrew Coleman with Raymond James.

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

I was wondering -- I missed a couple of the early comments on the tertiary side, but how are things moving along with the, I say, the Conroe Field? Is that still on track, I guess, to see injections in 2013?

Phil Rykhoek

Well, Conroe is actually expected in '14, but we'll give you an update of that at the Analyst Meeting. [indiscernible] that, that will factor in some of our CapEx guidance.

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

Okay. And are you guys still looking at adding additional CO2 fields or probably additional oilfields to the portfolio down in the Gulf Coast? And if so, how is the market down there currently?

Phil Rykhoek

I would love to. I mean, we always looking for additional fields, and we are looking at some. We have to reach a deal with the seller, and so that's really part of the holdup. That, I guess, I could probably say we may not be chasing that quite as hard as we used to because we have a pretty good inventory of fields and have growth for about the next 10 years, but as those become available or the -- we could get interested in someone selling them to us. We'd be happy to inventory them.

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

Okay, great. One last question, moving up into the Bakken. There's been a couple of good well results here in the last 24 hours, as well as additional commentary on some additional Three Forks plays. Have you guys looked at additional Three Forks locations on your acreage?

Robert L. Cornelius

Yes. This is Bob Cornelius. Yes, we are drilling some Three Forks. Right now we're still in the process of holding leases, but we're also looking at Three Forks. And yes, we have drilled some Three Forks, and we have had some pretty good results on those also.

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

Okay. Now what recovery factor are you looking at for your wells up in the Bakken right now?

Robert L. Cornelius

Well, it depends on where you're looking at. The Cherry area has really performed well for us, and so up in that area, we're looking at some pretty strong reserves, 5.75 for the Cherry area.

Phil Rykhoek

Yes, that's kind of our medium case or kind of the average case, I guess, would be the Cherry, which is about 5.75, and then there's a couple of areas that are slightly better than that and then there are some a little bit worse if you kind of get on the fringes kind of outside the center core area.

Operator

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

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

Just a few things I wanted to ask you about. At Jackson Dome, the Anderson well that you had, that was a development well, right, not an exploration well?

Robert L. Cornelius

Yes, it was a development well or it is development well.

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

Oh, okay. Great. And for the second well you're working on, do you have any pre-drill expectations for that?

Robert L. Cornelius

It's going to also be a right work well. It will also be a development well, so I don't know that we're going to add it other than the development, probably be something close to the Anderson.

Phil Rykhoek

The exploratory one's also drilling. That's the one that may add some additional reserves, but it could be anything.

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

Okay, fair enough. And you talked about possibly doing Oyster Bayou ahead of Hastings.

Robert L. Cornelius

Correct.

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

And when are you going to have a sense as to exactly which one you're going to proceed with first? Is that something you'll know pretty soon or...

Kenneth Craig McPherson

We will know that pretty soon. The current trend is it will be always Oyster Bayou first. It continues to be ahead of schedule both on the construction side and on the reservoir fill-up. So unless we see something in the commissioning, it's going -- we're going to start up Oyster Bayou first.

Phil Rykhoek

We prefer to start kind of one at a time because we kind of have, if you will, one startup crew. So we have to make that call fairly soon, but as Craig said, it looks like Oyster Bayou may get started getting first and would send the crew over to Hastings to start it after that.

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

Okay, great. And actually just to sort of drill down a little bit on a question that was asked before, it was this morning that Continental had -- or actually last night, Continental had put out a report on their theory that -- and actually they have one well and I guess, just proved that out that they see up to 4 different benches in the Three Forks. And they did their first well to the second bench, and it looked like it was pretty good. So I think what we're trying to get at is have you guys bid down a bit of seismic and quarrying in advance to try to identify these? Do you have any plans to look at different targets within the Three Forks in the near term?

Robert L. Cornelius

Yes, I heard those results too. They're pretty exciting. We're still looking at -- again, we're looking at Three Forks. I mean, we're looking at anywhere between 450 to 500 for the Three Forks and yes. So the answer is yes. We're looking at it, but we've got to do some more research on it. Again, we're trying to first hold leases, which is in the mid-Bakken, and then we'll move to the Three Forks afterwards. And by the way, too, just to add one more comment, the program that we have drilling right now, we're going to have all acreage held by the end of the first quarter. So by March, April, all of our leases will be held. Then, we'll move into a development program, actually, driven by results rather than driven by acreage exploration. So we'll be able to redirect some things after the first quarter.

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

Oh, terrific. So do you have any sense at this point just in terms of capital and your various priorities? I mean, would that give you the option to sort of slow down things a little bit in the Bakken if you wanted?

Phil Rykhoek

Well, yes. Again, you're getting into 2012. I know we're trying to kind of keep 2012 discussion postponed till to the 14th. But yes, it does give us a lot of flexibility. Of course, we do have rig commitment and so forth, and then also, as Bob said, we can focus on the best wells and do some development drilling and hopefully save a little cost and less rig movement and so forth. So I think it will be a overall improvement to our programming. We've been chasing lease explorations so far, and so we've been moving rigs a lot, and that of course adds to the cost and also, reduces the number of wells we can get drilled in a month.

Operator

We'll move to the line of Jeff Robertson with Barclays Capital.

Jeffrey W. Robertson - Barclays Capital, Research Division

Phil, in terms of the stock repurchases, can you all talk about how you balance the amount of that you're willing to do versus capital spending plans in 2012 and cash flow and how much you're willing to borrow to fund share repurchases versus -- at some point, maybe reducing capital spending to do that or reallocating capital spending?

Phil Rykhoek

Yes, I mean, I can't -- conceptually, we have said that we're very conscious of not levering up our balance sheet. So as we spend money on stock, we'll fund it with something else, most likely capital reduction in capital expenditures. We're also potentially looking at some small asset sales, again, probably have more detail at the Analyst Meeting. And I think we're probably going to present a case at the Analyst Meeting where we spend 250 on stock just to kind of take the middle case, because there's a lot of moving parts here. There's oil prices moving and the amount of stock we buy, moving stuff around and so forth. So it gets a little hard, but we're very conscious of the balance sheet. So I think we would go try not draw on our bank line very much in 2012 when you net everything all together.

Jeffrey W. Robertson - Barclays Capital, Research Division

And then secondly at Tinsley, can you all talk a little bit more about the well or the cementing issues and how long you think it will take to get that field or the rest of the wells checked out and get that work, the remedial work completed and back on -- with the field back on schedule?

Kenneth Craig McPherson

Yes, just a bit more color to the Tinsley issue, we've been injecting CO2 intensely since 2007 with no issues, and there's a -- within that field there were -- within areas that we've previously flooded, there was lots and lots of old abandoned wells and there were no issues with them. The problems we had encountered were in a localized geographic area that's flooding. What we noticed about that specific area is that there was a different company operator who had previously worked those wells over or worked on those wells and had abandoned them. Clearly, the quality of their work was poor, and the wells were not plugged in a manner that works consistent with regulations or industry standard. They had been reported to the state as properly plugged. They were not, and so we are going into those wells to properly plug them. That work will be finished over the course of the next few weeks. We're also in the process, as I mentioned, of checking other wells just to make sure that they are properly plugged. We believe they are, but we're just doing a bit more checking,due diligence, to ensure that they are. But we would expect in the fourth quarter, to have all of that work finished, to resume CO2 injection and put the field back on the upward trend.

Jeffrey W. Robertson - Barclays Capital, Research Division

So you wouldn't think that reducing the CO2 pressure and therefore the production in that area, the field would have much of an impact on how you book reserves in that field at the end of 2011. Is that correct?

Kenneth Craig McPherson

No, we see absolutely no long-term change to the ultimate recovery of Tinsley. In fact, as I mentioned also, we were starting to see a very nice response in these new patterns when this issue with this P&A-d well showed up.

Phil Rykhoek

Yes, Jeff, we've already booked reserves, pretty significant proved reserves at Tinsley, and we don't see this having any impact on that at all. There are still some probable reserves, but we would expect to get this -- that over time as we show the production responses and as you recall, we typically book somewhere in the range of 75% of our estimate as proven just to give us a little conservatism. Then, we hope we'll recognize that remaining 25% over the next several years. So no changes to the reserves at Tinsley as a result of this.

Operator

[Operator Instructions] We'll move to the line of Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly following up on the P&A issue, do you guys have recourse to the original operators or the people who did the P&A work there?

Kenneth Craig McPherson

No.

David W. Kistler - Simmons & Company International, Research Division

I'm sorry?

Kenneth Craig McPherson

No, we did not. These were wells that were plugged and abandoned, some in the 1940s and '50s. They go way back.

David W. Kistler - Simmons & Company International, Research Division

Okay. Switching over to the Bakken for a second, you've talked about the efficiency gains that you guys have experienced. Can you put those in the context of what that's done for well cost?

Robert L. Cornelius

Our well cost right now, when things go right, are running around $9.6 million to drill and complete a long lateral. If things don't go so well or we have a rig moved, it's running above $10 million. Probably about $10.4 million was the average of the last ones that didn't go very well. So -- but I think the efficiencies that we've gained -- and I'm just trying to use as many wells. I'm not trying to chop them into small groups. But some of those inefficiencies that we saw that drove our costs up are things that we have corrected either by getting better rigs or putting better people on our wells. Remember, we started this program from Encore with just 2 drilling rigs, we had to ramp up our first 5 and now to 7, and we've had to gain people and we gained a lot of experience during that time. So I think we're seeing some things. Again, our average cost if things go right, about $9.6 million, and if they don't, about $10.4 million.

Phil Rykhoek

We hope that once we get into some development drilling, we can shave some off that $9.6 million. Precise load is we're not sure, but at least a few hundred thousand. So we get to the low 9s, probably we'll get it down [ph] .

David W. Kistler - Simmons & Company International, Research Division

With the new rigs that you guys are bringing in there, currently, I mean, to the end of the year, shouldn't that also help push that down a little bit? And what kind of rate of change will you think about there? Or just what is your target for ultimate development drilling costs?

Robert L. Cornelius

Well, I think what we're trying to see right now is, again, we are getting to a point we're starting to hold acreage. So what we've done is we have started out looking at where we can drill twin wells, and automatically that shaves off $400,000. We're also looking at how we're completing the wells with some different completion techniques. So maybe we'll be down to $9.4 million, $9.5 million or maybe $9 million flat. Maybe we can get down to $9 million flat if things go right of course.

David W. Kistler - Simmons & Company International, Research Division

Okay, that's helpful. And then just in terms of the completions or just general service environment, is that starting to free up? Are you having any issues with getting additional frac crews as you've brought additional rigs in? Can you kind of give us color on how the landscape's changing up there?

Robert L. Cornelius

Yes, we've had agreement with several providers, and so, so far, we've not experienced too big a problem of getting our frac crews in there. We've been able to accomplish what we need to accomplish, and we hope to continue those relationships and add to those relationships.

David W. Kistler - Simmons & Company International, Research Division

Great. And then one last one, just looking at the wells that you mentioned earlier, Phil, where you list all the lateral lines, frac stages, et cetera or actually it's really frac stages, can you talk a little bit about the improvement in well production Q3 versus Q2, when it looks like frac stage has averaged about the same thing?

Robert L. Cornelius

I think what we've done is we've just -- like I said, we've learned a lot, and it's just more in efficiency of how we're frac-ing the well, and we're changing up a little bit of the way the pre-pads pump. We're changing the way the gels are mixed and the qualities and quantity of sand we're putting into the well. Sometimes, when you just start tweaking the small things and it's really a process as much as it is a mixture of what's going into the well.

Phil Rykhoek

Yes, pretty much what Bob gave you. Results for the last couple of wells in the Cherry, I mean, they're a couple of the best wells we've had to date, so we were generally seeing some, I think, some small improvements in the production rate.

Robert L. Cornelius

Yes, and then a lot of our reserves, the 11.5 million barrels is from the Cherry area where we've seen some significant increases in our reserves and what we used to book prior, that's helped us.

Operator

We'll move the line of Nick Pope with Dahlman Rose.

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Quick question, I mean just kind of as see Delhi starting to ramp up, where do you think production rates -- I mean where are you all going to focus on trying to get production rates at Delhi? How long is it going to take for that ramp-up?

Phil Rykhoek

Well, we expect it to continue to grow. I think if -- what does our slide show say, 5,000?

Robert L. Cornelius

I don't know.

Phil Rykhoek

I have to look at our slide show, I mean, to see what we expect Delhi to -- which one that is. We get that little chart and share what the expected rates are. But Delhi's performed well, so things do tend to sometimes plateau from time to time. As things move around -- actually it's 5 to 10, so I misspoke. So we got ways to go.

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Okay, sounds good. And I guess just kind of further on Tinsley, like when do you think kind of this plateau or this little near-term kind of dip, how long do you think that's going to last before you start to see the ramp-up again in Tinsley?

Phil Rykhoek

Well, we're -- actually fourth quarter, there's a chance that it actually slips a little bit because we have curtailed injections while we've been doing this well work. Then, we plan to start reinjection, as Craig said, in the fourth quarter, probably kind of late in the year, probably December. And then it may take a few months to pressure that up. So I think you're probably -- before you see significant growth with Tinsley, it'll be probably in the second half of '12.

Operator

And we'll move to the line of Gray Peckham with Susquehanna International.

Gray Peckham - Susquehanna Financial Group, LLLP, Research Division

Quick question on Delhi, you've mentioned a couple of times that you're getting faster-than-anticipated production response there. What's behind that? Can you kind of flush that out a little bit?

Kenneth Craig McPherson

Well, part of it is I just -- we were getting a good injection rate into the reservoir, the reservoir quality, probably a bit better than initially thought. As we've talked before, it's a bit of a challenge to understand just exactly how the reservoir will respond, and so we kind of take them -- the middle estimate at the range of possible outcomes, and the fact of the matter is Delhi is performing at the upper range of our expectations. And it's a function of reservoir quality as well as efficiency as how the CO2 goes into the rock, and from Delhi to Pearce, we have a very efficient sled.

Gray Peckham - Susquehanna Financial Group, LLLP, Research Division

And in the Bakken, we've heard a bunch of other operators say we're seeing kind of rapid increases in completion costs lately. Are you kind of able to mitigate those by your recent efficiencies? Is that how you're managing things there? Or can you give us some color on what you're seeing in terms of that market?

Robert L. Cornelius

Yes, we -- yes, again, we're -- the market is tight, but we do have some agreements with our providers. So like we've said, I think we can control it. Then, we are moving from a position where we used to have to move rigs long distances to hold leases, and now we're going to drill on multi-well pads. Again, with these flex rigs they're much easier, they -- we'll be able to have -- walking rigs that we have employed now, we've not been able to use those efficiently. So we're thinking that our costs are going to be still in a long lateral, about $9.6 million, and if you get some of those efficiencies, even drop that lower.

Operator

We'll move to the line of David Deckelbaum with KeyBanc Capital Markets.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Just have a quick question on the Bakken. Just wanted to -- not sure if I missed this, but as you all have now evaluated the Almond area, I guess letting that rig go is -- I guess to have like a seventh rig there, is there any reason to assume that perhaps it would move into the Cherry area and so maybe just accelerate that program a little bit?

Robert L. Cornelius

Well, what we did -- what we've doing is actually the well that drilled the Almond well, we actually released that rig for duties for Denbury. So we've completed that contract. What we're doing there, this comes to our efficiencies, we're moving in one of these high flex 3 rigs, and these flex 3 rigs move in much shorter time and they drill much faster. The hydraulics are better. The pumps are better. The train -- the crews are well trained. So we're just seeing our drilling time improve with these rigs. So actually, the rig count stayed the same because we picked up one of these flex rigs. At the same time, we dropped the rig that drilled on the Almond.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. So I guess as you cut down on the drilling times using the flex rigs and you're completing more wells with the same amount of rigs, is the price, I guess, for the incremental rig in the Bakken still in that $100 barrel range?

Robert L. Cornelius

No, I have not done that calculation. That's a new one on me. I can't answer that question. I'll have to go back and answer that.

Operator

[Operator Instructions] We'll go to the line of Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Just I missed the beginning of your call, so I apologize. But regarding Tinsley, the issue that you described today regarding the improperly P&A'd wells, that's a different issue than you described during the second quarter. Is that right?

Robert L. Cornelius

That's correct, yes.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. So can you just give us an update on the issue you described in the second quarter? I think it had to do with just the pressures related to injecting and producing and drilling, producing wells.

Robert L. Cornelius

Right. What was mentioned in first quarter was that we delayed injection a bit at Tinsley per our previous plan so we can get wells drilled and the patents developed. That work is done. Our work is completed, and so that comp in Q2 was just a reference to some previous assumptions made for how -- for the pace at which Tinsley would be developed in 2011. That development has occurred. So that issue, I believe, is resolved.

Phil Rykhoek

Yes, just to clarify timing a bit, when we announced that -- talked about that at the second quarter call in early August, I did mentioned the P&A problem briefly at the Barclays conference in early September. So it really is a new problem per se in a sense that I think that the market already has known. We've had problems with some P&A wells. What we're basically doing today is giving you more detail on that and telling you we see an end in sight, but we have had to go and look at a lot of different wells and work over maybe a bit more than we even initially anticipated. But that's really not a new issue per se, since I mentioned it in September.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Just sticking with Tinsley, my understanding is if I -- my look back at some old slides you did 3 or 4 years ago, Tinsley seems to be outperforming your initial forecast by a pretty significant amount. Is that correct?

Phil Rykhoek

Tinsley's been doing very well. Actually, it's been -- I mean, technically, it's actually been pretty much on forecast, but it's been performing very well. If you look at the curve, it's had steady growth since we started the flood. So it's been a very good flood.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then on the second quarter call, you also described an issue with conformance with Heidelberg. Any update on that issue?

Robert L. Cornelius

Well, the conformance work continues, and I mentioned we were working on a number of wells. That work seems to be going well. We'll continue that work through the fourth quarter, and so we just progress to -- I think, we've mentioned we worked on 30 something wells this past -- what we mean to say working on that 30 wells by year end, drill 3 wells, and we are having success in redirecting CO2 into the other target horizons.

Operator

Seeing no additional questions at this time.

Phil Rykhoek

Okay, well, thank you, everyone. We're happy to have a good quarter. I think we had very positive results, good growth in reserves. We're making good profit and so overall, good quarter. You might also even kind of do the computation of a proved NAV based on the new numbers that Bob gave you. I think you'll find that it's at current prices, which is in the low 90s or somewhere in the upper teens or approaching $20 a share on improving asset base on a PV-10 basis. So with that, just to remind you, our next conference is, of course, we had referred to 3 or 4 times today, but our Analyst Meeting on November 14, that will be in Houston. We plan to tour Hastings Field that morning, have a presentation in the afternoon. That presentation will be webcast, commencing at 2:00 p.m. Central Time. The slides for that Analyst Meeting will be on our website by that morning, the morning of the 14th. We, then, will follow that up with a presentation summary presentation or a shortened version in New York and Boston at the end of that same week, and just to let you know, I think this may be our last semi-annual analyst presentation. I think we plan to go more toward the annual format in the future. Our entire senior team will be at the Houston meeting, and then, Craig and I will do the New York and the Boston meetings. So we look forward to seeing you again soon. We'll have finished, additional information on November 14. Thank you.

Operator

Thank you. Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation and for using AT&T Executive Teleconference. You may now disconnect.

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 Q3 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts