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

Denbury Resources, Inc. (NYSE:DNR)

Q1 2010 Earnings Call

May 6, 2010 11:00 am ET

Executives

Phil Rykhoek - CEO

Tracy Evans - President and COO

Mark Allen - SVP and CFO

Bob Cornelius - SVP of Operations

Analysts

Scott Hanold - RBC Capital

Dave Kistler - Simmons & Company

Noel Parks - Ladenburg Thalmann

Mitch Wurschmidt - KeyBanc

Kevin Smith - Raymond James

Operator

Good morning and welcome to the Denbury Resources first quarter 2010 earnings release. (Operator Instructions) Please note this event is being recorded.

The following discussion contains forward-looking statements, and our actual results may differ materially from those discussed here. Additional information concerning factors such as price, volatility, production forecasts, drilling results, and current market conditions that could cause such a difference can be found in our reports filed with the Securities and Exchange Commission including our reports on Form 10-K and 10-Q.

I would now like to turn the conference over to Phil Rykhoek. Sir, please go ahead.

Phil Rykhoek

Thank you, Chad. Welcome, everybody, to Denbury and ENP's first quarter 2010 conference call. We plan to cover Denbury first, then, we'll follow with an update on ENP, and then we'll open up for questions.

With me today, I have Tracy Evans, our President and COO, Mark Allen, our Senior Vice President and CFO, and Bob Cornelius, our Senior Vice President of Operations. As you've probably noticed, we continue to have a lot of activity and lot of several positive events. Since, our last call, we have obviously closed on the Encore acquisition. We have entered into an agreement to sell most of our Encore Southern region properties for $900 million, which will get our leverage back to near pre-acquisition levels.

And we have had earlier than expected EOR production from Delhi Field. If you can sort through all the unusual items in this quarter's financial statements, underneath it all things are on track or ahead of expectations. Mark will cover these numbers in a little bit more detail, but let me briefly hit a couple high points.

As you can see from our first quarter production, operationally things are going well, with total company production at 86,578 BOEs per day if you include a full quarter of results from Encore. And of course, our tertiary averaged 27,023. As a result, we are increasing our tertiary oil production forecasts from 27,000 barrels a day for 2010 to 27,750.

And we plan to update the total company production guidance at the upcoming analyst meeting, adjusting for property sales. Although, I can report that non tertiary production is generally on track with our original forecast. So, things are looking good there also.

Bob will give you more details on production from our EOR properties, and Tracy is going to cover the recent results from our acquired Bakken and Haynesville assets. Our results from the Bakken wells, we recently fact are looking good, but I'll let Tracy give you the details.

With regard to property sales, our initial bids on the Haynesville have been less than we hoped for, so at this point in time, a sale of that property doesn't look too promising. The good part is that there is no pressure to sell, since we have already reduced our leverage, and it shouldn't be any problem to wait a little while and see if we get some help later from natural gas prices.

We do plan to let our operated rig go after it completes the current well in progress, so we are reducing our activity a little bit in this region due to the natural gas prices, although, we will still spend money there this year as much of our acreage is non operated and we are still being AFE. The Haynesville properties are still up for sale, so if things change we could pull the trigger later on.

But with that introduction, let me turn over to Mark to review the numbers.

Mark Allen

Thank you, Phil. As reported in our press release, Denbury had net income for the first quarter of $96.9 million. However, as we mentioned in the year end conference call, our first quarter results would have a lot of noise with several unusual or non recurring items.

First, since we closed on the merger with Encore on March 9, our first quarter results only included the operations of Encore from March 9 through March 31. In connection with the merger, we expensed $45 million in acquisition costs in the first quarter, representing advisory fees, financing, legal, accounting, integration, et cetera, that related specifically to the merger transaction.

Second, we incurred approximately $6.9 million of incremental interest expense for approximately one month due to our early February issuance of $1 billion of senior subordinated notes to finance a portion of the merger and redeem approximately $600 million of Encore's subordinated debt upon completion of the merger.

Third, we sold our GP and LP interest in Genesis Energy during the first quarter, and recognized a gain of $101.6 million on those transactions. Fourth, we had non-cash gains on the change in fair value of our commodity derivative contracts of approximately $101 million, all of these items before income tax effects.

And then, lastly, as a result of the merger, we increased our statutory tax rate due to our mix of new states and applied a new deferred tax rate to our deferred tax balances. In doing this, we increased our deferred tax expense for the quarter by approximately $10 million.

When you adjust for these items on an after tax basis, our adjusted net income for the quarter would have been approximately $17.4 million, principally due to the fact that we had a significant amount of our oil hedged in the first quarter with swaps at an average price of approximately $51.85 per barrel. Those swaps were only in place for the first quarter and going forward we have a much better mix of hedges, primarily collars, with ceiling prices near or above current prices. Please review our 10-K and most recent 10-Q that we will be filing for a complete list of those contracts.

As we have typically done, I will primarily focus on the sequential results for the fourth quarter of 2009 and first quarter of 2010. During the first quarter of 2010, our tertiary production was 27,023 barrels per day, 3% higher than our Q4 tertiary production and on an overall basis, Denbury's legacy production increased by approximately 4%, after adjusting Q4 production for the Barnett Shale, to approximately 41,700 BOEs per day in the fourth quarter.

And again, primarily due to the tertiary increase in production from the Conroe Field, which we acquired in December of 2009. Including Encore's production for the partial month, our total production for the first quarter was 53,125 BOEs per day. If Encore's production would have been included for the entire first quarter, total production would have been approximately 86,578 BOEs per day, roughly 75% oil and 25% gas.

As Phil mentioned, we have increased our tertiary production guidance for the year and would expect our overall production to follow suit. However, we plan to provide more detail on the combined company for the rest of 2010, at our upcoming analyst meeting at the end of this month.

Our average oil price received for the quarter, including derivative settlements, was $60.60 per barrel in Q1, as compared to $72.67 per barrel in Q4. But if settlement, if derivative settlements are excluded, our average oil price received for the first quarter was $76.53 per barrel, as compared to $72.56 per barrel in Q4.

Our NYMEX oil price differential was $2.08 per barrel below NYMEX in the first quarter, as compared to $3.44 below NYMEX in Q4. Assuming we had included Encore's production for the entire first quarter, our NYMEX differential would have been approximately $3.77 per barrel below NYMEX in Q1.

Our total lease operating expense up approximately $12 million from the fourth quarter, and on a per-BOE basis, our overall lease operating expense costs were down slightly from $20.34 per BOE in Q4 to $20.12 per BOE in Q1, primarily due to increased production in the first quarter, in addition of the Encore properties for the partial period.

If Encore had been included in our LOE for the entire quarter, we estimate our LOE per BOE would have been approximately $17.07 per BOE in Q1. Going forward, I would expect our LOE per BOE to increase a couple of dollars from this pro forma number after we sell the Southern assets.

G&A expenses increased by $4.6 million from Q4 levels, due primarily to additional G&A from Encore for a partial month and incremental compensation associated with more employees and higher bonus accruals in Q1. In the first quarter, Encore added approximately $3.7 million to our G&A for the partial month and would likely add $11 million to $12 million to our G&A for an entire quarter.

In addition, we will have some increases to this amount during the year due to severance and other costs associated with integrating the two companies during 2010, possibly $3 million to $6 million per quarter. Interest expense net of capitalized interest increased sequentially from $10.5 million to $26.4 million, primarily related to incremental debt incurred to finance the Encore merger.

As mentioned above, we issued $1 billion of new sub debt in mid February and increased our borrowings under our credit agreement in financing the merger. Average debt outstanding was approximately $2.2 billion in Q1, as compared to $1.3 billion in Q4.

Capitalized interest was $21.3 million this quarter, as compared to $19.9 million last quarter, primarily due to incremental interest capitalized on the green pipeline. Going forward, we expect that our capitalized interest will continue to increase moderately until we put the green pipeline into service. A portion of the line is currently expected to be put into service around mid year 2010. After that, we would expect capitalized interest to decrease to approximately half of the current amount per quarter for the remainder of the year.

Our bank debt at March 31 was $800 million under our new bank credit line and we had $250 million outstanding on ENP's bank line. We also had $2.276 billion of senior subordinated debt outstanding, including approximately $100 million of Encore's subordinated debt that was not tendered in the original tender offer.

All but a few million of this $100 million was put to us in the change and control offer, which ended in mid April and we used $66 million of the remaining escrow from our $1 billion issuance to cover this redemption.

In addition to incremental bank borrowings. Upon completion of the Southern asset divestiture, currently anticipated for mid May, we would expect to have very little bank debt at that time, but based on our anticipated capital spending, which is in excess of cash flow for the remainder of 2010, we would expect to see our bank debt increase throughout the remainder of the year, as we plan to outspend our cash flow by approximately $150 million to $200 million during 2010.

We estimate that our debt to cap ratio of March 31, 2010, pro forma for the pending asset sale and repayment of the sub debt that was tendered in April, would be a respectable 36% and debt to estimated 2010 EBITDA would be in the mid twos to one range on a go forward basis. We are pleased to get our leverage back to these more normal levels.

Our capital expenditure budget for 2010 remains at $1 billion, excluding acquisitions, capitalized interest, and net of anticipated sale leasebacks of approximately $50 million. On a combined basis, the $1 billion would exceed our anticipated cash flow by approximately $150 million to $200 million, assuming 12 months of combined cash flows for the two companies and based on current commodity prices.

Our capital expenditures, assuming a combined company for the entire first quarter are estimated to be approximately $230 million, as compared to $167 million, which was reflected in our financial information for the first quarter.

Our DD&A for the oil and gas properties increased on a per-BOE basis due to the impact of the Encore merger, the purchase of Conroe Field in Q4, and to a lesser extent, the remaining sale of the Barnett Shale properties in Q4.

With regard to our income taxes, we currently anticipate that we will be able to deduct a large portion of the green pipeline when we put it in service and begin injecting CO2 into Oyster Bayou, currently anticipated around midyear 2010. This should help limit our current tax expense and help shield additional tax on asset dispositions.

As a result of the merger, we increased our statutory rate, as I mentioned earlier, due to our mix of new states, and as a result of that we had to apply a new deferred tax rate to our deferred tax balances. In doing this, we increased our deferred tax expense for the quarter and our overall effective tax rate.

Going forward, our tax rate should be at a more normalized 39% or 39.5% rate. However, this could change again, depending on asset sales and other items.

And with that, I'll pass it to Bob.

Bob Cornelius

Thank you, Mark. I'll give you a quick update on operation activity and production at our major EOR fields during the first quarter. The EOR fields produced an average of 27,023 net BOEs during the first quarter. That's approximately a 3% increase over the fourth quarter and a 19% increase over the first quarter of 2009.

During the first quarter, we kicked off our 2010 CO2 EOR capital program, in which we plan to invest over $600 million EOR and CO2 development projects during the year. The major capital projects during 2010 are focused on key fields with investment designed to improve our operations and our growth rate during the next 12 months to 18 months.

Highlights of the first quarter were first EOR production and sales at Delhi, and then we also had double digit growth rates at Cranfield, Heidelberg, and Tinsley, as well as others.

First production and sales from Delhi was slightly ahead of schedule. If you recall, the CO2 injection was initiated during the fourth quarter of 2009, and then first CO2 EOR sales occurred during March of 2010. And unit production is ramping up nicely during March, averaging slightly above 300 net BOEs per day in that unit.

Production is expected to continue increasing during the year, as we add additional injection patterns and we see response from previously developed patterns. There is also a 28 well drilling program planned during the year, along with the expansion of the production in recycled facilities. At Cranfield, our Phase 4 CO2 project, production rates increased 28% quarter-to-quarter with an average first quarter production rate of 936 net BOEs per day.

We drilled four CO2 injection wells and one producer during the quarter. That should provide additional production growth later this year. On a side note concerning carbon capture and sequestration at Cranfield, Denbury and the Bureau of Economic Geology from the University of Texas have successfully and safely injected nearly 2 million tons of CO2 into Cranfield.

This joint project is demonstrating that CO2 injection into Saline Aquifers is a viable method of carbon capture and sequestration and we are pleased with the results of both our field operations and the information we were able to provide the scientific community, as well as the information we are receiving from the Bureau of Economic Geology and their important scientific work.

I am moving to Tinsley. Tinsley is our largest tertiary field based on natural production. It is located in Yazoo County, Mississippi, and it was approximately two miles from that devastating tornado that struck Mississippi in Yazoo County approximately two weeks ago.

Let you know our facility was undamaged. Although, we did lose electrical power for a short period, it only had a minor impact on our production rates. Tinsley Field continued to perform well during the first quarter, with a 12% production increase during the period. This is the second straight quarter where the unit experienced double digit growth and production increased from an average rate of approximately 2,390 BOEs per day in the first quarter of 2009 to 4,419 BOEs per day in the first quarter of 2010. That's an 85% increase over a 12 month period.

At the close of the first quarter of 2010, the unit now has over 27 CO2 injection wells and 61 unit producing wells. Injection volumes continue to increase and the Tinsley unit is expected to be one of our top performers during 2010.

Phase 2, consisting of Eucutta, Soso, Martinville, and Heidelberg, increased production approximately 3% quarter-to-quarter. Heidelberg's 13% and Martinville's 28% led the group with double-digit production increases during the period. Eucutta decreased 3% during the quarter, due a slight reduction in CO2 injection rates in prior periods.

The team is working to maintain CO2 injection rates and reserve and reservoir pressures. However, Eucutta is essentially developed, and so it has or is nearing its peak production rate. Soso production rate was flat quarter-to-quarter. The unit expansion continued at Soso with the installation of low pressure compressor and high pressure compression at the facilities.

Heidelberg continues to perform better than expected with an increasing production rate from an average of 1,506 net BOEs during the fourth quarter to 1,708 net BOEs during the first quarter of 2010. The next phase of unit expansion along with other 2010 capital investments should add production rates during the next two quarters.

Our Phase 1 fields, or the most mature areas that we operate, did not show a production increase quarter-to-quarter. They had a slight 2.5 decrease in production during the period. Phase 1 field Little Creek or Little Creek, Mallalieu, Brookhaven, McComb, Smithdale, and Lockhart Crossing. The most unanticipated increase was at Little Creek area, where production improved 12% from 1,480 net BOEs per day to 1,689 net BOEs per day.

Now, that production improvement during the quarter was due in large part to surveillance work conducted during 2009 that redirected CO2 into un-swept areas of the field. We see positive response to this WAG alternating gas, water/gas method test project at Little Creek.

This WAG project involves injecting nutrients to feed natural occurring bacteria into the formation. The nitrate rich water allows the bacteria to grow, which redirects the CO2 into other areas of the reservoir. The project has shown to increase aerial sweep efficiency and improve production. The team is considering expanding this WAG project to additional patterns and duplicate the success, if successful, this process could be applied to other fields in order to redirect CO2 into un-swept areas to recover additional oil.

Lockhart Crossing, Louisiana, tertiary production increased 10% quarter-to-quarter as production improved from 1,025 BOEs per day to 1,127 net BOEs per day over the period. The majority of the production increase is due to lower system pressures across the field, while maintaining reservoir bottom hole pressures. We continue to monitor reservoir performance and injection volumes to improve that production.

Moving to Jackson Dome, that's our CO2 source, it produced an average of 802 million cubic feet per day during the period. That's a 2% increase over the fourth quarter rate. [Phase 3 in Australia] was commissioned during the fourth quarter, and that allowed the addition of three wells that were not already producing. 2010 capital projects at Jackson Dome include the drilling of three wells and expansion or installation of dehydration facilities that we anticipate will improve production performance and add reserves.

Assuming things go as planned, we should have the results of our current well drilling at Jackson Dome by the analyst meeting later this month. This is an exploratory well. They're testing a target up to two tcf.

The Green Pipeline construction, recall that construction began back in November of 2008. The pipeline reached Oyster Bayou during December of 2009. And during the first quarter of 2010, valves, meters, and operation facilities were installed along the Louisiana portion of the pipeline. We completed the final tie in into the NEJD pipeline. That connects the Green Pipeline to the Jackson Dome.

The final commissioning work on this pipeline should be completed during May, with the first CO2 injection into Oyster Bayou commencing by mid year. There are three relative short segments of the pipeline to install this year to connect it to Hastings. There is a 20 mile piece from Oyster Bayou to the east side of Galveston Bay that work will begin during the next two weeks. We are already staging lay barges, moving pipe and equipment to get the 14 mile piece from across Galveston Bay, and that work will be completed in the next four to five months.

And then, we have another small segment 25 miles east of Galveston that will complete the pipeline into Hastings. All that work should be completed by the end of 2010. Going back to Oyster Bayou field, the work there is completed on the first several injection wells, and the team is preparing to lay flow lines to connect it to our CO2 source. Again, first production there is expected in May.

And then at Hastings, the technical team completed the initial pattern design and incorporated the reservoir modeling into the production and recycle facility. Injection is scheduled in early 2010, and Hastings EOR initial production is expected sometime late 2011.

I will turn it over to Tracy.

Tracy Evans

Thanks, Bob. I will give a quick update on our activity within the Bakken and Haynesville areas during the first quarter of 2010. In the Bakken, we continue to manage two drilling rigs in the Bakken. A third rig is contracted and should be moving into the area within the next several weeks. We are just waiting on the [North Dakota Frost Law] to allow that rig to move into the area.

Our plans for 2010 are to generally drill in the various areas operating throughout our Bakken acreage, but the third rig is planned to be located primarily in the Cherry, Camp, and Indian Hills areas. Our production during the first quarter of 2010 within the Bakken averaged approximately about 3,560 BOEs per day, with a preliminary estimate for April's production averaging approximately 4,200 BOEs per day.

The increase in production from the first quarter to April is primarily due to the three wells that we had fracd in the Bakken during the first quarter in which now we have 30 day average gross production rates. The [Wayor] Trust 4434, which was a 19 stage frac on a 1,280 acre unit, had initial production of 2,532 BOEs per day. That well has first 30 day average of 768 BOEs per day.

The Porcupine Ridge, 14 35H, that's a 12 stage frac on a 640 acre unit at an IP of 1,681 BOEs per day and at a 30 day average of 518 BOEs per day. The final well in the first quarter that was fracd was the Porcupine Ridge, 11X 2H, which had a 12 stage frac again on a 640 acre unit. It had an IP of 1,885 BOEs per day with a 30 day average of 628 BOEs per day.

We are currently in the process of flowing back the [Swenson] 3133 SWH, which is a well in our Charleston area, which has very good early results, and we expected, again, to be, have an IP in the order of 850 BOEs a day. That was a 12 stage frac on a 640 acre unit. The Becker 247H in Murphy Creek was drilled on a 1,288 acre unit and had a 20 stage frac design,, while running down hole tools to perforate the 12th stage, we encountered some difficulties and had to suspend the remaining frac and completion work, we are in the process of preparing the well in order to finish that planned completion in the near future.

The [Gilbert 11-26H], another well in Charleston on a 640 acre unit, is currently drilled and awaiting completion operations. And the [Hensen 11-12H] is currently running a 4.5 inch liner to finish the drilling of that well, the Hensen well is in the Murphy Creek area as well.

The results of these first few wells we have fracd, and the results of the offset operators, we are doing a complete review and assessment of our Bakken acreage. This includes expected reserves, forecasted production rates and our current development plan, and we should have all this updated in the very near future.

Within the Haynesville, we drilled two operated wells, the [Renfro] 5-1H and the [Korbies] 20-2H in 2010. We completed the [Dun] 2-1, which was actually drilled in 2009 in the Renfro, and we are currently drilling a third well, the [Purvis] 20-3H. We have also participated in 10 non-operating wells during the first quarter of 2010.

The two Purvis wells are on the same path and thus the completion of those wells will follow the finalized drilling of the 20-3H probably in early June. First quarter production averaged approximately about 3,200 BOEs per day within the Haynesville, and our preliminary estimated April production averaged over 4,500 BOEs per day.

A total of 12 either 2009 spud wells began selling gas in the first quarter of 2010, two of which were operated wells for Denbury. Production is expected to increase, as we complete our remaining two wells and as the non operated wells and drilling programs continue.

Four wells in the Greenwood Waskom area were completed with average IPs of about 9 million cubic feet per day in the first quarter. Two non operated wells in the Kingston area were completed with average IPs of 25 million a day and one non operated well was completed in Caspiana at just under 9 million cubic feet per day.

In the Exxon joint venture, we maintained activity during the first quarter with two rigs running. One rig is focused on the Pegasus field with the drilling of the Wilson 46 number one and the Pegasus unit 44-7. The second rig was committed into the Delaware basin and drilled the Hodge 8-H during the first quarter. The completion of the Hodge is yet to occur, but should occur in late May. The assets associated with the Exxon joint venture are included in our planned sale of assets and is expected to close this month.

Just a brief note on our sale process. The due diligence on behalf of the purchaser is continuing, and they should be essentially complete in the next several days. Consents, pref rights, and other customer activities associated with a property package the size are ongoing, and that's why we expect to close the transaction by the month, as we had discussed.

And with that, I'll turn it back to Phil.

Phil Rykhoek

Okay. Thanks. Let's change the focus just a little bit, and talk a little bit about ENP. As most of you saw late last week, we announced that we were reviewing strategic alternatives for ENP. We've received numerous inquiries about the implications of this pending sale on our future plans for ENP, and I'd like to address that briefly.

As you also know, we recently announced that Denbury's entered into the agreement to sell most of the Southern region assets that we acquired through Encore, assets primarily in the Permian, Mid Continent, and East Texas. Several of these properties could have been potential dropdown candidates to ENP, given the nature of their reserves and production. But as a result of the sale, they will no longer be available for dropdowns, assuming the sale closes as expected.

Furthermore, most of Denbury's remaining assets require significant capital expenditures in order to recognize their potential value and therefore would not be appropriate properties to drop down to ENP and given the nature of our focused EOR strategy, it's unlikely we would acquire properties that are appropriate dropdown candidates in the future.

So, from Denbury's point of view, we want to explore growth strategies for ENP other than a traditional series of dropdowns from MLP's general partner. In light of these considerations, we intend to explore a broad range of strategic alternatives to enhance the value of ENP units, including but not limited to those involving a sale or merger of ENP or of Denbury's interest in the general partner. Quite simply, that means, we could possibly merge ENP with another MLP or we may sell the general partner interest of ENP to another entity.

But in either case, the goal would be to do a deal with someone that will continue to manage and grow ENP and we will attempt to structure any possible transaction such that it is not dilutive to cash flow per unit or asset value per unit.

One other thing, we'd like to accomplish in this strategic review is to find a way to recognize the potential value of CO2 tertiary projects that are in ENP, the biggest of which is [Upbasin] field. I think we'd all agree it is not practical to do an EOR flood within an MLP due to the substantial capital investments required for a tertiary flood. So, Denbury is reviewing alternative structures or transactions which could be pursued by ENP, Denbury, or a combination to allow development of this field, again the focus being without diluting the value of ENP's units or reducing ENP's distributions per unit.

Of course, there is no assurance that a review of strategic alternatives will result in the completion of any transaction. We are just getting started in this process, so we wouldn't anticipate having any news or updates on this for some time, and we likely won't announce anything until we have a specific transaction to discuss.

We need to agree on a specific transaction with another party. We need approval from the conflicts committee at the ENP Board, and we need sign off from the various investment bankers, who will be involved looking out for the various interests, as they will be providing fairness opinions. So, obviously, we have a lot to do, but our goal is to find something that will be positive for all concerned.

I think Mark will now review a little bit of the ENP numbers.

Mark Allen

As we announced last week, the distribution for the first quarter of 2010 was approved at $0.50 per unit, as compared to $0.5375 per unit in the fourth quarter of 2009. In determining this distribution, we continued to apply the variable distribution policy previously established.

Our cash available for distributions was $27.9 million in the first quarter, as compared to $36.7 million in the fourth quarter, the decrease principally due to lower cash receipts on commodity derivative settlements due to the expiration of favorable contracts in 2009 and higher lease operating expense due to work over expenses in the first quarter.

Our coverage ratio for the first quarter remained strong at above 1.2 times. Production for the first quarter totaled 9,034 BOE per day, as compared to 9,254 BOE per day in the fourth quarter of 2009. Going forward, we expect production to continue to be on a low decline for the remainder of 2010.

As mentioned in the press release, our G&A expense was higher in the current quarter due to two non cash items, the expensing of phantom units that vested upon the change of control when Denbury acquired Encore, and approximately $937,000 related to the bank debt waiver paid by Denbury that must be pushed down to the partnership, as an expense even though Denbury will not be reimbursed. We repaid $5 million in bank debt during the quarter, bringing our bank debt to $250 million at March 31.

And now, I'll turn it back to Phil

Phil Rykhoek

Okay. That concludes our prepared remarks. So, Chad, if you could come back on, let's take some questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Scott Hanold with RBC Capital. Please go ahead.

Scott Hanold - RBC Capital

Thanks, good morning guys. On the Bakken, it sounds like you guys are becoming much more encouraged with what you're seeing out there. In terms of, when you are looking to complete these wells, obviously with the industry looking at these higher intensity frac stages, do you sense that you are going to start to push the limits, look at 20-plus stage fracs? And can you give us a little idea of around how you are doing some frac designs, how many stages, what kind of completion? Are you using sliding sleeves or plug [impervs] and the type of profit you are looking at?

Tracy Evans

Scott, this is Tracy. We probably don't have all that detail today. But we are looking at the number of stages. Obviously from where we have had this, obviously the number of stages has increased from prior times. I think, we are primarily using plug imperv, primarily, as our completion methodology as well. And we will get you further details on that but I just don't have that information right off the top of my head.

Scott Hanold - RBC Capital

Okay. Is it fair to say you guys are becoming encouraged with those two wells you've had?

Tracy Evans

Yes.

Scott Hanold - RBC Capital

And so, are you going to look at some both Bakken and Three Forks wells, or are you really going to just kind of focus on the Bakken right now?

Tracy Evans

We actually have both going on, actually. The Wayor Trust and one of the Porcupines were actually (inaudible) wells, and then we have a couple middle Bakkens, too. So, they are looking at both formations.

Scott Hanold - RBC Capital

And one last kind of Bakken like question here, just from a high level, you've got, what, roughly again, around 300,000 acres. Based on what you know today, how much do you think that looks very prospective at this point?

Tracy Evans

I still think most of it looks prospective, other than probably the Almond area and maybe that Northeast foothills, which I think was about 75,000 acres, so probably 225,000 or so.

Scott Hanold - RBC Capital

Okay, fair enough. And then, one last kind of housekeeping question. On discretionary cash flow for the quarter, what are the adjustments that need to be made that you kind of can take out some of the non-recurring items this period?

Mark Allen

They should be listed on the attachment to the press release. I think you should see those. I'm not sure if you, we add back, obviously the --

Scott Hanold - RBC Capital

Okay, so just to clarify, then, is that $66 million sort of, quote/unquote, clean number for cash flow during the quarter?

Mark Allen

Yes. That's just the cash flow for operations, yes.

Scott Hanold - RBC Capital

Okay. Got it. That is what I was looking for. Thanks.

Mark Allen

There are some other non recurring things you could, I mean, we've only kind of backed out the normal, but obviously you have some non recurring things related to the merger related costs and such that are flowing through there. But we typically back out the hedging aspects.

Operator

Thank you. Our next question comes from Dave Kistler with Simmons & Company

Dave Kistler - Simmons & Company

Just a clarification point, one of the exploration wells that you're referencing on the CO2 side, is that the Dry Dock well that you hope to talk about at the analyst day?

Tracy Evans

Yes, that would be the Dry Dock.

Dave Kistler - Simmons & Company

Okay. And is there any reason, I think on the last call you guys thought it would be about 30 days to 60 days. That's taking a little longer, potentially or am I just misinterpreting the last call?

Phil Rykhoek

No, I think, we always kind of said we'd probably have results at the analyst meeting. It's getting close, but we're just not quite there.

Tracy Evans

Yes, we've not had any significant drilling problems, and really we're right on the curve, so we might just misspoke.

Dave Kistler - Simmons & Company

No worries. Could have been my misunderstanding. Staying on the same thing, the theme of CO2 for a bit, can you talk a little bit about timing on the DKRW loan guarantee or anything on the Exxon LaBarge agreement, as well as other CO2 contracts you might be pursuing up in the Rockies area?

Tracy Evans

Not specific to DKRW, but I have talked to several of the loan guarantee guys over the last probably two weeks. It looks like they are looking at late second quarter, maybe early third quarter to get some of that government stuff lined out. And then, on Exxon LaBarge, we are still talking to them. There is no contract at this point.

Dave Kistler - Simmons & Company

Are there other CO2 agreements you are pursuing in the area at this point?

Tracy Evans

Within the Rockies region, yes, and the Gulf Coast as well.

Dave Kistler - Simmons & Company

Can you give us any color on the Rockies specifically?

Tracy Evans

It's primarily the gasification project, like DKRW. You actually have a couple others up there, the Many Stars project. We're still talking to Dakota Gas as well. We have a project over in Idaho. So, if there is CO2 being talked about in the Rockies, we are probably talking to them.

Phil Rykhoek

It's pretty much the same things that we've outlined on the slideshow with the possibilities.

Dave Kistler - Simmons & Company

Great. I appreciate that. Then, just looking at the tertiary recovery right now, and a little bit of an up tick on a number of different areas, is any of that related to installing jet pumps into some of the plays, or can you talk a little bit more about what you're doing with the jet pumps and whether you might be using them going forward, given that obviously we are seeing up ticks in responses?

Bob Cornelius

Yes. This is Bob. We are using jet pumps. Anywhere that we have a well that is not responding with early responding, we'll place that jet pump on. I think it's going to help us hit our forecast a little closer than we have in the past. And yes, we've continued to use them at Soso especially.

Phil Rykhoek

Bottom line, we are just trying to manage the floods a little better and stay on top of things. And jet pumps help us with non responding wells, and this water alternating gas sometimes help with other things. So, it's just the day-to-day management and we are obviously trying to do a better job with that.

Dave Kistler - Simmons & Company

Great. Well, I appreciate the added color, guys. Thank you.

Operator

Our next question comes from Noel Parks with Ladenburg Thalmann. Please go ahead.

Noel Parks - Ladenburg Thalmann

Good morning. Just a few things. Actually, one thing that came up on the call, you mentioned in one of the fields using, I guess, this bacteria method as something that actually has helped production and that it has been encouraging enough that you are planning to roll it out in some other areas. That was a surprise for me because my understanding had been that that was pretty speculative, that thing that you were working on. So, it has turned out more promising than you had assumed?

Phil Rykhoek

We had one test going on, and the issue is trying to determine how much of it is due to the lag versus how much is due to growth of the bacteria. It's kind of hard to determine when you get two things going on at the same time. So, we are trying to resolve that to see which one. We are going to expand it in terms of trying to do may be just a WAG and then another one with bacteria.

So, we are still trying to figure out what the exact cause of the increase is, but no doubt we've got the increase, which is a positive thing. And just gives us another tool out there in order to increase our aerial sweep efficiencies.

Noel Parks - Ladenburg Thalmann

Sure. And is there any meaningful incremental costs to using the bacteria?

Tracy Evans

No, the bacteria is pretty cheap. We don't actually inject bacteria. The bacteria is in the formation. Basically, what we are injecting is fertilizer.

Phil Rykhoek

Nitrogen-rich water. We put water with a little bit of nitrate in it.

Noel Parks - Ladenburg Thalmann

Okay. And I don't know if you said this and I just missed it, could you just tell us what the status is of the existing production in Conroe, just its trend, maybe, quarter-over-quarter?

Mark Allen

It was between 2,000 and 2,500. I don't know the exact number, but it hasn't changed much, maybe just down slightly, a little. I've got the number here in a second.

Noel Parks - Ladenburg Thalmann

Great.

Mark Allen

2,269.

Noel Parks - Ladenburg Thalmann

Okay, thanks. And the Green Pipeline coming or the end of the road for that long haul project is finally being in sight. As far as your cash CapEx spend, as you head towards the end of that project in the next few quarters or so, what is going to be your last major cash spend, which quarter is going to be your last major cash spend for the line, and how do you see it tailing off going forward?

Mark Allen

Total for this year, 2010, is about $150 million. And I think, we are going to start, like we said, we are staging the equipment at both the Galveston Bay and over in Oyster Bayou. So that equipment's being staged now. So, you're going to see a ramp up during June, July, August, and in September it should start tailing off, and by the end of December it should be tail off because we'll just be completing the line into Hastings at that time.

Noel Parks - Ladenburg Thalmann

Okay. So, for the rest of the year, would you say, I don't know, ballpark, say two thirds of the rest of what you have to spend would be that third quarter period and/or, I guess June, July, August, second, third quarter period? And then --

Mark Allen

Yes, I think that's probably accurate. Then the final third would be into November, December.

Noel Parks - Ladenburg Thalmann

Okay. Great. And one more thing on the Green Pipeline. There was some mention about your anticipating some tax deductibility of the Green Pipeline once it goes into service. Could you just explain a little bit more about that?

Mark Allen

Yes. This is Mark. A couple years ago, we went to the IRS and got the ruling on tertiary operations, and these are considered 493 deductions. So, when we put them in service when we began injection, we would be able to expense those costs. So that is basically the crux of it. So that particular item is still under audit, and so we're working through that. But that was the initial ruling we received from the IRS.

Tracy Evans

Just one other clarification on Scott's previous comment. He may have spoke a little bit, I understand what he was asking. The $66 million in our adjusted cash flow, I think he was wanting to know what unusual items we could add back to that. And yes, definitely the $45 million of merger related costs would go back against, or head back to that, and also the duplicate interest that we paid on the first quarter, which should be around additional $7 million, would be the two items that kind of jump out there.

Operator

Our next question comes from Mitch Wurschmidt with KeyBanc. Go ahead.

Mitch Wurschmidt - KeyBanc

Hi guys, now that you have 30 days on these Bakken wells, just any thoughts on, I guess, early EURs on those types of wells?

Phil Rykhoek

Yes, we have some early thoughts.

Mitch Wurschmidt - KeyBanc

Thoughts that you can share.

Phil Rykhoek

They're higher what we originally thought. Looking back in the last couple of days, as we made the acquisition, the average, a range of EURs that we had estimated were probably in the 225,000 to 300,000 barrel. I think now, looking at some of these initial wells, we are probably moving that up to greater than 300,000 on average. But that is what we really need to get through and evaluate these wells. I mean, 30 days is, it's definitely very, very positive, but another couple of months will really help define what we really think the reserves are. But we are definitely moving up.

Mitch Wurschmidt - KeyBanc

Okay, fair enough. Is it fair to say you'll have some color on that on the Analyst Day coming up?

Phil Rykhoek

I hope so.

Mitch Wurschmidt - KeyBanc

Okay, great. And just moving on, on Delhi, any thoughts or can you share any thoughts on potential reserve adds in 2Q based on what you're seeing from that so far?

Bob Cornelius

We would expect as production continues to ramp up that we would do our historical about 75%. I think, the number right now is 33 million barrels on a 17% basis. So, probably around 75% of that is what we probably would expect.

Mitch Wurschmidt - KeyBanc

Okay, great. So, good booking there. And then, can you just remind me, too, on Oyster Bayou, when we can kind of expect first production from that? It sounds like injection is coming up here soon.

Bob Cornelius

Yes, I think, we might've misspoke. I don't think production will happen in May this year, anyway. Probably May of next year.

Tracy Evans

Maybe next year. Yes, May 2011.

Mitch Wurschmidt - KeyBanc

Okay. It'll probably be more in 2011 timeframe, maybe early 2011, do you think?

Phil Rykhoek

Mid 2011.

Mitch Wurschmidt - KeyBanc

Mid 2011. Okay, great. Thanks a lot, guys. Congrats on getting everything closed.

Operator

(Operator Instructions) Our next question comes from Kevin Smith with Raymond James. Go ahead, sir.

Kevin Smith - Raymond James

Thank you. Just one question on Encore Energy Partners. What type of capital spending program are you expecting for the next few quarters?

Mark Allen

Kevin, we are working on that hard. The original budget that was drafted was about $6 million of spending. We did outspend a little bit on this, extra LOE project during the year, so that's what we are working on right now, is trying to develop a little clarity around that capital plan for 2010 and into then to 2011, looking at the opportunities that we have within ENP. We would expect that $6 million, $5 million to $6 million, would be the number. It's just as far as exact projects and things like that we need to identify those a little clearer.

Kevin Smith - Raymond James

Okay. But I guess, for the second quarter, you don't have anything operated that you are drilling or working on?

Mark Allen

No, not currently.

Operator

Again we have a follow up question from Noel Parks. Please go ahead.

Noel Parks - Ladenburg Thalmann

Hi, one thing I did forget to ask, about the Bakken, you said that you were planning sort of a re-evaluation of it in the near term. And other than the EUR expectations changing that you commented on, what other things might you decide or determine from that process?

Phil Rykhoek

Reserves are probably the biggest one. But you have production rates. Obviously, we are seeing some probably higher production rates that what we'd originally anticipated based on our acquisition. And then, we are looking at the development plan in terms of how many rigs are needed to maintain and develop this acreage in the future. All of that is going into this review.

And then, we are also looking at trying to continue to test and determine the Sanish versus the middle Bakken in that as well. That data takes some wells to be drilled, obviously, in order to do that. But we are looking at that as well. Down spacing, we are starting to look at that as well.

Noel Parks - Ladenburg Thalmann

Okay. Do you have any plans to re-approach, now that completion practices have changed a lot, some of the areas of the former Encore Bakken acreage that didn't have particularly good results when the initial wells were being drilled, either sort of in the general vicinity of where they've got a lot of other activities, sort of, say, Kenzie County, or even heading further out to the Northeast?

Phil Rykhoek

Right now, we have no plans to go out to the Northeast. That would probably be that Almond area. We're probably not going to focus on that. But we are looking at some of the areas. The Cherry area was an area that initially did not show as well with some of the prior completions. We are definitely targeting that with this third rig.

Noel Parks - Ladenburg Thalmann

Great. So, we might see some more drilling there, I guess, second half of the year, then?

Phil Rykhoek

Correct.

Operator

This concludes our question-and-answer session. Now, I would like to turn the conference back over to Phil Rykhoek for any closing remarks.

Phil Rykhoek

Thank you, everyone. I know there's a lot of conference calls going on, so if you have further questions, we'd be happy to take them if you'd like to call me or one of the other guys afterwards.

Just in closing, I'd like to remind you, we have our annual meeting coming up May 19. I appreciate your support on the matters we are putting to a vote in that proxy.

Then later this month, toward the end of May, we are holding our spring analyst meeting during which we will provide more details on each of the operating areas, supplemented by additional financial data. At that time, we also hope to present some numbers showing what the company would look like following our asset sales, and we may also try to pull out ENP, since that is also potentially in progress.

We plan to use a similar approach as we did last spring, group presentation in New York, followed by one-on-ones with our entire senior management team, followed by a day in Boston, Chicago, San Francisco, and Los Angeles with Tracy and myself. So, if you want to schedule one-on-ones or check on any of the other planned conferences or trips, please contact [Lori Brooks], our IR manager in our office.

But most importantly, stay tuned. A lot of positive things are happening here at Denbury, and we look forward to a great 2010. Thank you.

Operator

The conference has now concluded. Thank you for attending today's presentation. 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, Inc. Q1 2010 Earnings Call Transcript
This Transcript
All Transcripts