Denbury Resources' CEO Discusses Q2 2011 Results - Earnings Call Transcript

Aug. 5.11 | About: Denbury Resources (DNR)

Denbury Resources (NYSE:DNR)

Q2 2011 Earnings Call

August 04, 2011 11:00 am ET

Executives

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

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

Kenneth McPherson - Senior Vice President of Production Operations

Robert Cornelius - Senior Vice President of CO(2) Operations, Assistant Secretary and Member of Investment Committee

Ronald Evans - President, Chief Operating Officer and Member of Investment Committee

Analysts

Gray Peckham - Susquehanna Financial Group, LLLP

Scott Hanold - RBC Capital Markets, LLC

Pearce Hammond - Simmons & Company International

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Welcome to the Denbury Resources Inc. Second Quarter Conference Call. Today's call is being recorded. Joining us today will be Phil Rykhoek, Chief Executive Officer; Tracy Evans, President and Chief Operating 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 Production Operations.

The company's comments today will include forward-looking statements consisting of opinions, forecasts, projections or other statements other than statements of historical facts, which are made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based upon our current assumptions, estimates and projections regarding Denbury and the external markets and economic conditions. These statements are subject to a number of risks and uncertainties that are detailed in our SEC reports, which may cause actual results in future periods to differ materially from our forward-looking statements.

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

Phil Rykhoek

Thank you. Welcome to Denbury's First Quarter Conference Call. I think our moderator has already introduced everybody who is here, it's our senior team and what we call internally our investment committee.

Our bottom line results this quarter were at record levels. Adjusted net income roughly $147 million, 41% increase sequentially over the last quarter, and invested cash flow was just over $344 million, which was a 27% sequential increase. Of course, the reported book operating income results were quite good with reconciled items being noncash, nonrecurring items, and Mark may touch on that a little bit.

For those of you that focus on cash flow multiples, you might want to take a look and notice that the cash flow we generated this quarter was our best quarter ever. Personally, I encourage you to also look at our net asset value. And I think that may be a better stock valuation measure, and I think you'll find we're significantly undervalued based on that metric.

As I mentioned in the press release, there are many positive aspects to this quarter. We had record quarterly cash flow. We reduced our operating administrative expenses per BOE on a sequential quarter basis. We recorded the best-ever NYMEX oil price differentials, thanks to the positive LSS oil markets. And actually, those items were -- the directed cash flow and the positive NYMEX differentials were achievable since we have over 90% of our production in crude oil.

We expect production growth to accelerate next year, as construction of our new facilities on schedule at Hastings and Oyster Bayou fields, with initial oil production expected there soon, and our Bakken oil production results continue to be strong. We are gradually accelerating in our activity in that areas. We plan to add 2 additional operating rigs before year end.

All these things are positive, but to me, one of the more important things that happened this quarter was the acquisition of the remaining interest at Riley Ridge. If you missed the significance of this deal, this acquisition gives us control of the vast natural resources of Riley Ridge and a source of CO2 that we anticipate will be less expensive than Jackson Domes's CO2, which was already one of the least expensive in the industry.

Although we have just begun our engineering, and therefore, we don't have precise numbers, we expect the revenue from the natural gas and helium to cover the projected development costs, and most, if not all, of the incremental costs of extracting the CO2, resulting in a very inexpensive source of CO2, if you look at this project as one combined CO2 operation.

We do expect to spend more capital at Riley Ridge over time, than we have today at Jackson Dome, but the big difference is we have a revenue stream from the natural gas and helium to pay for that investment. Jackson Dome simply doesn't have that.

We also believe that this source will ultimately provide more CO2 than we need for existing properties, allowing us to pursue other oil properties that are EOR candidates in the Rocky Mountain region. This acquisition is a big step for Denbury, as we strive to replicate our Gulf Coast EOR strategy in the Rockies. Bob will give you a few more details on the acquisition in a minute.

Before I turn it over to the other guys, I also want to briefly discuss production. As I have often stated, predicting the timing of the EOR production is one of our more difficult tasks. We realized how important it is, and we are always striving to improve our accuracy, but due to the nature of this business, this will always be difficult and always have margin innovator. In fact, we find it somewhat easier to forecast the Bakken production, as evidenced by our relative better accuracy, in spite of a tough weather this spring and significant competition. Craig will give you more details/updates and provide additional color regarding our EOR activities. But to keep things in perspective, I wanted to quickly review with you our recent forecasting results.

If you look at our last 3 years, in 2009, we nailed the forecast almost exactly. In 2010, we beat the EOR forecast by almost 8%. And it looks like for this year, we're going to be about 5% short. So perhaps on average, you could say we're slightly ahead. But I think the most important thing to remember is the short-term production variances have not reduced our expectations of oil that could be recovered from these floods, just the timing. The process works and works well, and I'm proud to be associated with the company that -- with such unique profitable and repeatable strategy. We have an extensive inventory of tertiary projects, as was previously mentioned. We expect to see initial productions soon from 2 new floods: Hastings and Oyster Bayou. These new floods should draw our production growth in 2012, which we expect to be significantly higher growth rates in 2011. We are building the foundation for 2012, which should be a great year.

With that as an introduction, let's look at more details for the quarter, and we'll start with Mark's review of the numbers.

Mark Allen

Thank you, Phil. I'm pleased to report that Denbury achieved record profitability levels in the second quarter in both income and cash flows, coming in ahead of consensus on both adjusted EPS and cash flows. I will spend the next few minutes providing more announcements on the numbers and provide some forward-looking projections. Our comparative analysis were primarily focused on the sequential results of the first and second quarters of 2011.

As reported in our press release, Denbury had adjusted net income for the second quarter of $146.7 million or $0.37 per basic common share, as compared to adjusted net income of $103.9 million or $0.26 per share in Q1. Adjusted net income is a non-GAAP measure that excludes certain items such as fair value hedging gains and losses and another unusual and non-recurring items, which we believe 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 $259.2 million or $0.65 per basic common share is included in our press release.

In the second quarter, we had fair value hedging gain of $183.8 million due to the decrease in NYMEX oil future prices at the end of June, as compared to the end of March, which essentially reverse the $172 million fair value hedging loss we had reported in the first quarter of 2011. Our cash flow from operations before working capital changes increased from Q1 from $271.2 million to $344.1 million in Q2, a company record.

Our total company production for Q2 was 64,919 barrels of oil equivalent or BOE per day versus our production for Q1 of 63,604 barrels of oil equivalent per day. Our tertiary production averaged 30,771 barrels per day, essentially flat with the 30,825 barrels per day in Q1. Our Bakken production averaged 7,626 BOEs per day, compared to 5,728 BOEs per day, a 33% increase over Q1. We'll go into more detail on our production results in a few minutes.

Our average oil price received, excluding derivative settlements, was $106.30 per barrel in Q2, as compared to $93.67 per barrel in Q1. Our crude oil derivative contracts reduced our net oil price by $3.13 per barrel in Q2, as compared to $0.95 per barrel in Q1. On a total company basis, our NYMEX WTI oil price differential was a positive $3.72 per barrel in Q2, as compared to $0.59 per barrel below NYMEX in Q1.

For our tertiary production, the average NYMEX price differential was a positive $9.69 per barrel in Q2 as compared to a positive $4.33 per barrel in Q1, with some of our tertiary production receiving average positive differentials in excess of $15 per barrel during the second quarter. Differentials in our northern properties also improved, with our Bakken production averaging $9.62 per barrel below NYMEX in Q2, as compared to $11.55 per barrel below NYMEX in Q1.

As I mentioned in the last quarter conference call, beginning in late January 2011, the LLS oil price begin trading at a significant premium to the WTI NYMEX oil price, since then, ranging from approximately $10 to $24 higher than WTI. Since roughly 40% of our oil production is marketed on an oil price that incorporates this positive LLS differential, this has provided a nice benefit to Denbury.

In general, the average of this differential goes into our pricing formula that is realized in the following month. Also, there are other pricing competitiveness that go into the pricing formula, so we likely will not always realize the full benefit of this differential, but it will generally be within a few dollars. We currently anticipate that our company-wide NYMEX differential should remain strong in Q3, however, we are not sure of how long the LLS differential will remain at these levels.

Our hedging positions have remained relatively unchanged since Q1, and we are hedged at roughly 75% to 85% of our anticipated crude oil production to the end of 2012. For the second half of 2012, we increased our full price from our typical $70 to $80 per barrel, and our average ceiling price is around $128 per barrel for the same period. Most of our oil hedges for 2011 have a core price of $70 and a weighted average capital of around $100. However, it is important to note that we have contracts in 2011 with caps ranging from the low 90s to $106 per barrel. So we do have some exposure to cash hedging losses with oil prices even in the low 90s. We paid approximately $17 million for settlements on our oil hedges in Q2, while cash settlements on our gas hedges provided us $6 million of cash in the second quarter.

Although our lease operating expenses were up approximately 2% from Q1 to Q2, our lease operating expenses on a per-BOE basis decreased from $22.20 per BOE in Q1 to $21.99 per BOE in Q2. The decrease on a per-BOE basis was due primarily to increased Bakken production, which has a lower production costs in our tertiary operation and lower per BOE expense for our tertiary production.

LOE for our tertiary operations averaged $23.35 per barrel in Q2, as compared to $25.40 per barrel in Q1 due primarily to lower workover costs. Going forward, I would expect that our total company LOE per BOE will remain in the $21 and $22 range.

G&A expenses decreased from $43.8 million in Q1 to $30.9 million in Q2. As I stated in our first quarter conference call, our first quarter G&A expenses is higher than normal due to incremental compensation related to items such as payroll taxes and 401(k) match to year-end bonus payments, and vesting of long-term incentive awards, which primarily vests in the first quarter.

In addition, the true-up of compensation associated with long-term incentive awards and performance awards, moving costs associated with our relocation to a new corporate headquarter and higher professional fees associated with year-end work, all contributed to the higher Q1 costs.

During the second quarter, our incentive compensation expense returned to more normal levels, and in some cases, decreased due to updated performance estimates for 2011. Also professional fees decreased by approximately $1.9 million. Another compensation expense such as payroll taxes and 401(k) decreased by almost $5 million.

For the remainder of 2011, I would expect our that G&A expenses would be in the range of $35 million to $38 million per quarter with approximately $8.5 million to $9 million of that expense related to stock-based compensation.

Interest expense, net of capitalized interest, decreased sequentially from $48.8 million in Q1 to $42.2 million in Q2. Capitalized interests was $13.2 million in Q2, as compared to $11 million in Q1. Average debt outstanding was $2.3 billion in Q2, as compared to $2.5 billion in Q1. The decrease due primarily to the lower bank debt and repayment of $125 million of subdebt associated with our hedging financing in Q1.

Going forward, we currently expect that our capitalized interest will be around $13 million to $15 million for quarter during the remainder of 2011, depending upon the certain assets going to service.

We had no bank debt outstanding on our $1.6 billion credit line at the end of the second quarter, and we had $122 million of cash. We recently borrowed $125 million on our bank line to close the Riley Ridge acquisition, and we estimate that we may at the end of the year with somewhere around $200 million to $225 million drawn on our bank line, depending on many things, including the timing of capital expenditures, cash flows and working capital requirements.

Our capital spending budget increased $1.3 billion to $1.35 billion, related to incremental capital expenditures as a result of the Riley Ridge acquisition. Our capital budget amount assumes that we are able to enter into equipment leases for approximately $60 million, excludes acquisition and excludes the approximately $100 million in capitalized interest in the tertiary startup costs across at Hastings and Oyster Bayou Field. Our estimates also assumes that a similar level of capital caused the carryover in 2011, as we had in 2010.

For 2011 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 on hand at the end of 2010. Therefore, estimated borrowings on our bank line will essentially be related to our acquisition-related activities during 2011.

Our metrics continue to improve, with our debt-to-capital ratio at approximately 33% and our debt-to-Q2 annualized adjusted cash flow at approximately 1.7x.

Our DD&A per BOE increase to $17.52 per BOE in Q2, as compared to $16.35 per BOE in Q1. This increase is primarily due to increases in future development costs associated with reserve additions and cost increases and capital expenditures in Q2. We added approximately $30.9 million BOEs from the Bakken during the first 6 months of 2011, and since funding of development costs associated with our Bakken reverse is generally higher than our historical DD&A rate, it tends to drive up our DD&A expense on a per-BOE basis.

We currently estimate that the Riley Ridge acquisition will potentially lower our DD&A per BOE slightly, but future reserve additions in the Bakken may offset some of this benefit.

Our statutory income tax rate is estimated at 38%, with our effective rate just under 39%, due primarily to nondeductible expenses that drives up our rates. Going forward, I anticipate that our tax rate would be around the same rate as our current tax rate with current taxes ranging from 6% to 10% of that amount, assuming we are able to take advantage of certain deductions under the new Tax Law. Most of our current taxes are associated with state tax liability.

And with that, I'll turn it over to Tracy.

Ronald Evans

Thank you, Mark. I'll give a little more color on the reserves as of midyear. Primarily as a result of our activities in the Bakken during the first 6 months of 2011, we have added an additional $29 million BOEs of reserves to our proved reserves. Our total proved reserves as of June 30 are estimated to be $417 million BOEs, that consist of 353 million barrels of oil, condensates, and natural gas liquids and 385 Bcf of natural gas. The net present value of the reserves, based on the midyear product prices, is approximately $9.3 billion compared to a year-end value of $7.3 billion.

Incidentally, the $9.3 billion would infer a trued net asset value of approximately $17.50 per share at $91 oil. Total reserve adds during the first 6 months were 30.9 million BOEs. the 30.9 million BOEs of additional reserves do not include the estimated 250 Bcf of natural gas or 41.7 million BOEs of reserves, associated with our recent acquisition of the additional interest at Riley Ridge. The remaining reserve adds between the Bakken and the total number were primarily associated with performance revisions or due to the higher oil price that existed at June 30 versus year-end. Product prices used in the midyear estimates were $90.90 per barrel and $4.31 per million Btu, compared to $79.43 per barrel and $4.45 per million Btu at year end.

Drilling activity in the Bakken continues with 5 rigs, as mentioned, ramping up to 7 rigs later this year. This activity is expected to result in additional proved reserves during the second half of the year from the Bakken. We continue to evaluate our well results, nonoperating well results and offset wells, in which we have no interest in order to better refine our reserve estimates.

The Cherry area continues to show better-than-forecasted production rate and is an area that estimated individual well reserves for the middle Bakken approximately 50,000, 100,000 BOEs per well were increased based on the performance to date.

Tertiary reserves remain relatively unchanged at 159 million barrels after adjusting for 2011 production. With the status of our CO2 injections raising the reservoir pressures at Hastings and Oyster Bayou, we are forecasting first response for this deals in late 2011 and early 2012 respectively. And as such, expects significant additional proved reserves in 2012 from these 2 fields. As we've stated before, reserve additions in the CO2 are somewhat lumpy when compared to reserve additions in a drilling play like the Bakken.

We have completed our review of the well data and seismic data at our DRI Dock Field, and as a result, we have reduced our reserve estimates at DRI Dock by approximately 238 billion cubic feet of CO2. Our drilling program at Jackson Dome continues with expected reserve additions from 2 wells later this year. A third well remaining for this year is expected to provide additional deliverability of CO2 later this year from the Gluckstadt Field.

On the anthropogenic side, we continue to monitor the status of CO2 capture projects, in which we have purchase contracts. Mississippi Power continues to make progress in the construction of their Kemper County IGCC plant with expected first deliveries in 2014 of approximately 115 million cubic feet per day, and their products is making progress in advancing their capture project as well down in Port Arthur, with first delivery is expected in late 2012 or early 2013 of approximately 50 million cubic feet per day. The majority of our other projects continue to make progress. But at this time, the expected date of first deliveries from these other projects is very difficult to estimate.

With the acquisition of Riley Ridge and the signing of our CO2 contract in the first quarter, we believe we now have secured sufficient CO2, and in fact, more CO2 than we need for our existing operations in the Rocky Mountain region, assuming we further develop and continue the development of the Riley Ridge area and our projects -- anthropogenic projects continue to proceed as we have in the forecast.

And with that, I'll turn it over to Bob.

Robert Cornelius

Thank you, Tracy. I'll quickly discuss our second quarter Bakken activity, the Riley Ridge acquisition in more depth and then report on the major pipeline of CO2 projects.

The Bakken team continues to see these improvements into the drilling completion processes, as well as in the overall the operation. Operation improvements are evidenced in several areas including our production rates, drilling time and a number of completions during this period. Bakken production rates improved during the second quarter, with production averaging 7,626 net BOEs. That's a 33% increase over the first quarter Bakken production rate. Although North Dakota experienced a colder than normal spring, along with a record rainfall and road lane limitations. The team was able to fracture and complete 11 wells during the second quarter. That's compared to 5 fracs during the first quarter.

Drilling time measured from spuds to rig released inquiries improved. And we have seen a decrease in the number of days required to move some of our rigs. Comparing drilling time now to the first quarter, we saw an average of 59 days or some along laterals during the winter months during the first quarter. That's been reduced to 40 days average. We're drilling the same type of long laterals during the second quarter, and recently a drilling time of 34 days is accomplished for a long lateral and 29 for 640-acre location. The drilling team also went into a fixed frac-ing agreement that should improve or shorten the number of days required to move our drilling rig.

As reported, Denbury's drilling at 5 wells operating in the Bakken. We contracted to add 3 new efficient [indiscernible] in the basin. The first rig will arrive late in the third quarter and the next 2 rigs will be placed in our operations during the fourth quarter of this year. Ultimately, we will finish the year with 7 operated Bakken drilling rigs.

An agreement was also completed with Halliburton to assist in project management. All of these services, the project management, the new drilling rig, trucking agreements are designed to further improve drilling efficiencies, improve completion performance and reduce overall downtime.

Completion process also improved during the second quarter, as we frac-ed 11 wells during the period. 7 of those 11 wells were completed in the Cherry area and McKenzie County. The average initial potential for our Cherry completions was just over 1,800 BOE per day. Several recent IPs in the areas where the Loomer 34-4, which IP-ed at 2,574 net BOEs per day, and the Lundin 11-15 southeast horizontal, that had initial potential of 2,135 net BOEs per day. For the complete list of all of our Bakken completion, you can see our web page.

So with improved weather conditions and continued well results, we are forecasting that we will be able to close much of the production gap that we lost in the first [indiscernible]. However, I think it's going to be unlikely that we're going to offset the weather-related operational impacts that occurred earlier in the year. So our forecast now shows we exit the year with the Bakken production rates of somewhere between 11,000 and 12,000 net BOEs per day and average annual rate, which will approximately be 8,400 net BOEs per day.

As Tracy discussed earlier, our latest acquisition, we closed on Monday, August 1, and we completed that acquisition that acquired the remaining 57.5% working interest in the 9,700 acres of Riley Ridge Federal unit and the adjoining acreage of 28,000 acres, we have a 33% working interest. Denbury is the operator of both of these units.

Strategically, the Riley Ridge Federal Unit will provide us with approximately 434 net BOEs of natural gas, 15.5 Bcf of helium, and probably more importantly, approximately 2.4 Tcf of CO2, that's Denbury's interest in units. Initial production of CO2 is expected probably in 4 to 5 years, and we have to construct additional processing facilities to separate the CO2 from the remaining gas stream, and of course, the construction of a CO2 pipeline to our EOR field.

For the most part, much of the expense in the pricing of CO2 would be carried by the sale of methane and helium. The adjacent 28,000 operating acres of which we own 33%, we are estimating the same [ph] reserves between 250 to 300 Bcf natural gas 9.5 to 11 Bcf helium, and another 2 to 3.2 Tcf of proven CO2, net of Denbury's interest.

Although the development of these reserve is 7 to 8 years out, the adjoining acreage becomes quite strategic, while it feels like to say, this is the Jackson Dome of the Rocky Mountains. In some ways, this Riley Ridge area maybe even better than our Jackson Dome, as this massive reservoir in the Riley Ridge area may have total CO2 reserves greater than the Jackson Dome area. And we have projected methane and helium sales to assist in covering the CO2 development costs.

As the pipeline construction in the Rocky Mountain area, we are preparing to construct the 232-mile 20-inch diameter Greencore Pipeline that is going to connect ConocoPhillips-operated Lost Cabin processing facility to Bell Creek in Montana. At this time, we are waiting on the final approval from BLM to start that construction. Denbury is beginning to position proven equipment in anticipation of the final approval. Construction is scheduled from late August through November in the Natrona, Johnson and Southern Campbell Counties, Wyoming. The pipeline will be constructed in 2 building seasons. The first 115 miles pipeline will be target construction date, as I said, late August to November. And a final segments are expected to be completed during the fourth quarter of 2012.

Now if we do not get the timely BLM permits, we would plan to build the entire pipeline in 2012 rather than breaking it into 2 segments. That can easily be accomplished. In the Jackson Dome area, CO2 daily production averaged over 1 Bcf for the first 6 months of the year. So it's record production rates we continue to search for new reserves in the area. We have a drilling rig working in the Gluckstadt Field, where we are drilling a location. This location has the opportunity to deliver increased CO2 production rates and it also could add additional proved reserves. Our plans are to add a second drilling rig in the area during the latter part of September or during the fourth quarter that could test other geological structures that could prove up a portion of the 5.6 Tcf of probable and possible reserves in the Jackson Dome area.

With that, I'll turn the other operations over to Craig.

Kenneth McPherson

Okay. Thank you, Bob. I'm going to provide an overview of our CO2 EOR production operations for the last quarter, as well as an update on the total company production outlook for the balance of the year -- for the rest of the year.

Tertiary production averaged 30,771 barrels of oil equivalent per day during the second quarter. This is essentially flat to tertiary production in the first quarter of 2011. Compared to the second quarter of 2010, tertiary production has increased by 2,264 barrels of oil equivalent per day, and that's an 8% increase. A high-level summary of our second quarter tertiary production is that our mature fields' decline was essentially offset by increases at Delhi, Tinsley and Heidelberg.

With that, I'll just -- I'll start moving through the phases, and give you a brief overview of what's going on there. In our most mature operating areas, Phase 1, production decreased by approximately 8% quarter-to-quarter through an average rate of 11,037 barrels of oil equivalent per day. There were a number of well repairs Brookhaven Field during the quarter, which resulted in lower CO2 injections and contributed to the production decrease.

In general, Phase 1 is entering the decline portion of its life. Production from Phase 1 is expected to modestly declined from quarter-to-quarter fluctuations, as performance, work and other optimization activities are performed.

Phase 2. Phase 2 production dropped by 380 barrels of oil equivalent per day compared to the first quarter, which represents a modest 3% decline. Of note is the Heidelberg Field. This production grew by 5% compared to the first quarter of 2011.

While we had a production increase, we were expecting more rapid growth in production, similar to how the field responded last year. Our investigation indicates that the more modern production growth we are experiencing is due to not getting CO2 plays into all 10 sand layers within the reservoir. This has also lowered the predicted reservoir response and associated production. This type of challenge is roughly common in those secondary and tertiary floods, especially in reservoirs with multiple sand of varying permeability with rock characteristics vary across the field. The industry uses the term conformance to describe this.

To address this challenge we've modified our reservoir management plan for Heidelberg, so we can redirect more CO2 into the unswept intervals. Intervention work includes modifying the zones into which CO2 is injected in specific wells changing perforation intervals, and we'll likely drill a few new wells. We believe that Heidelberg's ultimate recovery is unchanged. However, the modified reservoir management plan to address the conformance issue will result in a more modest production increase, followed by a larger plateau period rather than a larger near-term increase previously anticipated.

Phase 3. Tinsley Field production grew by 423 barrels of oil equivalent per day, and that's 6% compared to the first quarter of 2011. We're pleased that production is growing. However, we have slowed the 2011 development phase compared to what we originally forecast. We did not anticipate the same rate of growth during the second half of 2011 as we originally planned. We had forecasted reservoir will develop several new patterns this year by accelerating the drilling of the CO2 injection wells for multiple patterns.

We did sequentially drill several CO2 injection wells, and we quickly started getting CO2 into the patterns. Filling up the reservoir with CO2 increased the reservoir pressure, which caused some unanticipated challenges drilling the new producing wells offsetting the injectors.

We showed several injection wells this past quarter so to allow the reservoir pressure to moderate, so we can more easily drill the producers. We've now finished drilling 5 of the 8 planned 2011 pattern. And we're ramping back up our CO2 injection. We expect the remaining 3 patterns to be brought on injections by October.

Although our efforts accelerate production from Tinsley has been delayed, Tinsley will continue to be a great tertiary field with significant production growth. It's just that the rapid production increase anticipated in 2011 will instead give more modest increase, followed by an anticipated significant increase in 2012. This reflects the reduced CO2 injection volume this year in the new patterns. Estimated ultimate recovery is unchanged.

Sustaining [indiscernible] this is obvious. The reason for the change at Tinsley's 2011 production profile is very different than what I described for Heidelberg.

Phase 4. Cranfield's production increased by 9% to do the successful repair of one of our better wells, which had impacted our first quarter production.

At Delhi, which is Phase 5, we are joining a faster-than-anticipated production increase as a reservoir response to CO2. Production increased by 739 barrels of oil equivalent per day, which is a 48% increase compared to the first quarter. We're very pleased with Delhi's response and expansion of that field continues.

With that, we'll move to the future CO2 field and let's start with Phase 7. We started injecting CO2 at the Hastings Field in December of 2010. The goal is to build reservoir pressure up to our planned operating pressure by December of this year. CO2 injections on schedule, as is plant construction. We're very pleased with the progress to date, and we still anticipate the startup date of late fourth quarter 2011.

Phase 8. The Oyster Bayou, we began injecting CO2 during June of 2010. Similar to the story of Hastings, CO2 injection is on schedule as is plant construction. We're very pleased with the progress and we anticipate a startup late in the first quarter of 2012.

Phase 9. At Conroe, our conventional fracture production was 2,826 barrels of oil equivalent in the second quarter. In preparation for the future CO2 flood, we're surveying the proposed CO2 pipeline route into the Conroe Field.

Moving to lease operating costs, just a few comments there. Regarding these operating costs, during the second quarter of 2011, operating cost for our tertiary properties averaged $23.35 per BOE, compared to our first quarter 2011 average of $25.40 per BOE. Tertiary operating costs were down approximately $5 million compared to the first quarter, and that's primarily due to reduced workover costs. As you recall from our first quarter call, workover costs were a bit higher due to the accelerated wellbore repairs at Brookhaven in the first quarter.

Let's now move to the full year forecast, as that complete our production operations over the year. As Bob mentioned, we continue to be very encouraged by our Bakken well results. The sustained poor weather still makes project execution and delayed production. Also, due tat the constrained regional natural gas processing infrastructure, we flared on average approximately 35% of our produced salable gas.

Even with these challenges, we believe we'll be able to make up much of the deferred Bakken oil production in the second half of the year, assuming sustained good weather and continued well results. For forecasting Bakken production to average 8,400 barrels of oil equivalent for the full year, which is 300 barrels a day equivalent lower than previous guidance.

As previously mentioned, 2011 tertiary production is being impacted by Heidelberg's still modified reservoir management plan to resolve the injection conformance and by Tensley Field's extended execution of pattern development. Accordingly, we're forecasting our 2011 tertiary production to average approximately 31,000 barrels of oil equivalent per day, which is 1,500 barrels a day lower than previous guidance.

Combining tertiary Bakken and another conventional production together, total company production is forecast to average approximately 65,600 barrels of oil equivalent per day this year. This represents an 18,000-barrel a day equivalent reduction to previous guidance given. For this point, we're revising the 2011 full year production target downward. However, I do want to reiterate that the causes for the reduced reduction do not represent the diminished outlook for the ultimate recovery of the fields. Weather and gas infrastructure in the Bakken, the forced CO2 injection in Tinsley and CO2 injection conformance work at Heidelberg are the primary drivers of the change.

That concludes our remarks I'll turn the discussion back over to Phil.

Phil Rykhoek

Thanks, guys. Obviously, a lot of good information from them. We'll open it up for Q&A. Ernie, can you come back on?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

Phil or Tracy, on the tertiary production, I guess, that the Heidelberg, where it looks like it's coming a bit softer. I think you gave some pretty good explanation that it doesn't look -- that the CO2 is getting to everywhere you need it to. And remind me, is this different than what occurred -- what was at McComb a couple of years back and you had this sort of change your injections in this well too?

Ronald Evans

Yes, Scott, this is Tracy. Yes, it's completely different. The McComb issue was we couldn't get the CO2 on the ground at the pressures we had designed where the project's at. And Heidelberg, we have no problems getting CO2 on the ground. The problem is you have 10 individual reservoirs that all have their own properties. And obviously with CO2, we have very low viscous fluid. It's going to go to the path the least resistant. And so what's happening is it's going in certain of the interval at the 10 intervals, primarily 2 or 3 of them. And as you know very well, but are not getting CO2 into the other one. So if you remember how we forecast, it's [indiscernible] subjective for reserves. We're not getting the CO2 in those reservoirs that's why it's not -- that's why we need to get the ramp that we expected this year. So it is completely different. We get CO2 on the ground harder. that's not the problem. You just got to get it in the right sand and keep some of it from going into these higher perm stands.

Scott Hanold - RBC Capital Markets, LLC

So when you do that, what is sort of the incremental capital costs doing something like that? Is it like drilling other wells, specifically, targeting those areas? Or is this just perfing existing wells to get to your -- how logistically does that work?

Kenneth McPherson

We believe -- this is Craig. It's going to be about another $1 million this year and probably $4 million to $5 million actually next year will be the incremental cost of the conformance work, which has already began. I mean, it could be anything from relatively inexpensively dumping stand and blocking off lower stand. You have to get sands in the middle. You may have to do squeeze work and reincorporating stuff like that. But again, as a total per well, it's not very much. But it will add up to about $5 million or so. And we have already adjusted the development plan on the east side. This is East Heidelberg. This is all West Heidelberg. So we're hoping not to have the same issues. I mean, we will have the same issues, we don't expect it to cause the change in the forecast.

Scott Hanold - RBC Capital Markets, LLC

Okay. And I guess, my sense is that it sounds like in every field has its own little nuance that you're certainly got to be aware of. When you look at Hastings, Oyster Bayou, Conroe, is there any thing in those reservoirs, based on your experience with McComb and Heidelberg and Tinsley that you've learned that maybe applicable there as well?

Ronald Evans

Well, I don't think so. I mean, when you look at Hastings, you look at how we developed it. We recognize that we had multiple sands. We're doing 4 simultaneous floods, doing 2 sands or 3 sands at a time versus trying to do Heidelberg like 10. Oyster Bayou and Conroe are really one sand to begin with. They do have their own differences and that they're very thick. And so we're looking at some things there to make sure that we get CO2 throughout the entire intervals. But you're right. Everyone is slightly different, and we do use a similar forecasting methodology at the end. But honestly, until we start the injection and see how our aerial sweep, how the CO2 is going in individual sands, it's difficult to say how exactly how they're going to react. So but now, we won't have any problem injecting into or having no problem injecting into Hastings. We're having no problem injecting in Oyster Bayou. We won't have any problem injecting into Conroe. This is really more of a conformance issue that it is being able to get CO2 on the ground.

Scott Hanold - RBC Capital Markets, LLC

Okay, all right. And then Moving to the Bakken, you all mentioned, I think you said, you have 5 rigs running and you're getting 3 new builds by the end of the year.

Ronald Evans

That's correct.

Scott Hanold - RBC Capital Markets, LLC

And then there is a mention of -- you'd have 7 rigs running by the end of the year. Is that -- does that imply that you just dropped one of the other rigs you have?

Robert Cornelius

Yes, this is Bob. On a rig schedule, we have one of our rigs is going to continue to drill probably another 3 to 4 wells. And then we will go ahead and release that, and replace it with a more efficient rate. These rigs that we're having, they'll be easier to move and we started our pad drilling. We'll be moving easily from one well to the other on the existing pad. So yes, we will end up with 70, now we're adding 3.

Scott Hanold - RBC Capital Markets, LLC

And how many -- remind me how many frac-ers do you have contract or frac, I guess?

Robert Cornelius

We have 5 fracs per month. And we're looking to try to add another one as pick up another rig.

Scott Hanold - RBC Capital Markets, LLC

Okay. And so 5 frac dates gives you probably enough to what [indiscernible] provide a specific program, right? Is that about right?

Robert Cornelius

Yes, definitely. If you take in the time it takes to move and those type of things. And we're fortunate that we have a good relationships with our providers, to service companies. So we've been able to, in some instances, even pick up and do a 6 rig in a month or 6 frac in a month so we hope we'll be able to do.

Scott Hanold - RBC Capital Markets, LLC

Okay. And one last question on the Almond area, it sounds like you're in a test go up [ph] there in terms of the back half the year. What's the plan there? How many wells do you need to get down before you sort of make the decision? Is this basically a couple of wells and then you kind of either like it or don't like it? Or don't like it or is it going to be a little more extensive?

Robert Cornelius

We have 2 wells scheduled for the Almond area, here in the third and fourth quarter to test it.

Phil Rykhoek

We'll make a decision as we go based on that gap.

Operator

We will go to the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Just a couple of things. Returning to Heidelberg for a second, I do remember that when Heidelberg was on the horizon a few years ago, the thought was that it was pretty similar to Eucutta. And if remember right, the cost of Heidelberg was supposed to be lower because it didn't have as many sort of old plump wells to be reentered. Did --has that analogy not panned out quite as you thought between 2 fields?

Ronald Evans

Well, I do think the costs [indiscernible] they have. I mean, we're not reentering hardly any wells. We have plenty of wells. So that's true. The difference between Eucutta and Heidelberg, Eucatta basically has 3 sands, the flood, we have 10 here. And it is the same formation as the Utah formation. So I mean, it is responding similar to Eucutta. The main difference is this conformance issue of getting the CO2 in all 10 sands as they need to be. With only 3, Eucutta, is a little bit easier.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I got it. And the way that you expect these different sands will interact and vary and how they take in CO2, is that pretty similar across the field or are there areas of the field where some of the sands are just going to be more challenging than others?

Ronald Evans

If you could isolate each sat individually, they would CO2 just fine. It's -- you have a fixed pressure, and therefore, it really depends on what your permeability is in each reservoir as to what will go in them. And what we're seeing now is we have some very high perm zones that tend to take the vast majority of the CO2. And that's one of the reasons why the response was so great early on is because all the CO2 is going in those and not much in these lower ones. So now we got to get the CO2 in these lower perms zones. I now take it in various wells that's not the issue. It's just getting it designed the way that we have it forecasted.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Got it, okay. And thinking about the adjustments to we made in Heidelberg, and also changing up the pace at Tinsley a little bit, as you look forward and start doing your budgeting for next year, is -- did those changes have much of an effect on what you might be doing in your overall plan for the year?

Robert Cornelius

No, I mean, when you look at Heidelberg, we already made the modification in East Heidelberg in terms of -- over there it's the Stanley 1 that is going to be the sand that take a lot of CO2. We're isolating here in certain wells, we're not perforating in others. So we've already made that adjustment on the East side of Heidelberg. And as far as Tinsely, no, I wouldn't modify our plan. I think we got probably a little aggressive this year trying to advance the stuff. And fortunately, with injecting the CO2 and then trying to drill at the same time, it just wasn't a good situation.

Operator

[Operator Instructions] We'll go to the line of Gray Peckham with Susquehanna International.

Gray Peckham - Susquehanna Financial Group, LLLP

Quick question about your Gulf Coast CO2, given the reduction of your reserves expected there at DRI Dick, can you just remind us of how your CO2 supply lines up with your future needs down in the Gulf Coast?

Robert Cornelius

well, even with the -- it's 200 Bcf, 7.1 Tcf. So you're talking about a very, very small reduction. It easily could be offset almost by performance, upper performance revisions at year end at our existing CO2 field. So really -- it's this point that we're on that's disappointing. But it's really a nonevent in terms of our CO2 supplies for the Gulf Coast.

Phil Rykhoek

Which we're still testing a lot of that, as Bob mentioned 5-plus Tcf are probably impossible. So we're still very optimistic that we had more CO2 there. And secondly, these man-made sources are still on track in the Gulf Coast. So short answer is, we don't -- it's not a problem.

Operator

We do have a question from the line of Pierce Hammond with Simmons & Company.

Pearce Hammond - Simmons & Company International

I was curious if you could provide any update or your current thoughts on the possibility of trading your Bakken assets for some EOR.

Phil Rykhoek

Well, I guess no news. I don't know if that's good news or bad news. It's just, I guess, the only was to answer is it's still a possibility, but obviously, we have to move very fast in some of the -- or if we talked to or -- of our nature, they don't move very fast. So in the meantime, we're not too worried about it. We're increasing our activity there going from 5 to 7 rigs, and production is growing. So I guess it's still an option, but we're proceeding as though it has happened and development of the field on a more rapid basis.

Pearce Hammond - Simmons & Company International

Phil, and then on cost inflation, what's your outlook when you look at the Bakken? And then also compared to tertiary?

Phil Rykhoek

I'll let Bob...

Robert Cornelius

Well, I mean, you are seeing more competitive -- there's a lot of competition in the Bakken. Right now, the long laterals were pushing at about $9 million per well. And about 7.5 to 7.8 on short 648 [indiscernible]. But again, we've got some processes and things that we're putting in place in the Bakken to improve our efficiencies and reduce downtime. It's all about the number of days are down. So we're just trying to put it back in place by trucking agreement, with these more efficient rigs and we're working with service companies to reduce that downtime.

Phil Rykhoek

I mean, in short, we'll probably see a little higher rate of inflation in the Bakken than EOR just because there's more competition. But we're having some cost increases of a little bit everywhere just to begin.

Ronald Evans

Yes. The biggest one on the tertiary side is steel. I mean, steel prices are definitely going up 10%, 15%. So that's a big part of the tertiary project. It's not 100%, so it's not -- our costs have not gone up to 15%. But it is -- as far as the biggest thing portion of our tertiary costs that's going up. Obviously CO2 [indiscernible] costs goes up as oil prices than the downward oil prices, so it ranges just where oil prices are.

Pearce Hammond - Simmons & Company International

That's very helpful. And then lastly, I'm not sure if you can answer this but I know your partner was in the process of completing their first well in the Tuscaloosa marine shale. I'm just curious if you had any update there?

Ronald Evans

Well, the only update we can have is that our partner is EnCana. But that has not to release any well results until they're ready. Well, we can't really release any well results.

Operator

There are no further questions in queue. And Mr. Rykhoek, I'm turning the call back over to you.

Phil Rykhoek

Okay. Well, thanks, everybody. Just to give you a little update on upcoming events, our next 2 conferences will be the Intercom Conference in Denver on August 15 and 16, and then the Barclays conference in New York on September 6 and 7. We'll have our entire senior team in Intercom, and Craig and I will be up at the Barclays Conference. I also promised a trip to Midwest so we're tentatively scheduling that for the week of September 19. And please check with Laurie if you want to set up a meeting in these events.

And then also just looking ahead, we'll have more further details in the future. You might mark your calendars for a full Analyst Meeting, at least tentatively we're scheduling for November 14 and 15. We're going to go down to the Hastings Field, just outside of Houston. So that might be easier for you guys particularly from the East Coast to get down there. And we will give you more details on that as we get a little closer. So we look forward to seeing you all again soon. Thank you for your support of Denbury. Goodbye.

Operator

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

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