Denbury Resources' (DNR) CEO Phil Rykhoek on Q2 2014 Results - Earnings Call Transcript

Aug. 6.14 | About: Denbury Resources (DNR)

Denbury Resources (NYSE:DNR)

Q2 2014 Earnings Call

August 06, 2014 11:00 am ET

Executives

Jack T. Collins - Executive Director of Finance & Investor Relations

Phil Rykhoek - Chief Executive Officer, President and Director

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

Kenneth Craig McPherson - Chief Operating Officer and Senior Vice President

Analysts

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

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

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Richard M. Tullis - Capital One Securities, Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Denbury Resources Second Quarter 2014 Results Conference Call. [Operator Instructions] I would now like to turn the conference over to your host for today's call, Jack Collins, Denbury's Executive Director of Finance and Investor Relations. Please proceed, sir.

Jack T. Collins

Okay. Thank you, Roxanne. And good morning, everyone, and thank you for joining us on today's call. Presenting from Denbury on today's call will be: Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; and Craig McPherson, our Senior Vice President and Chief Operating Officer.

Before we begin, let me remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause actual results to differ materially from what is discussed on today's call. You can read our full disclosure on forward-looking statements and the risk factors associated with our business in our corporate presentation, our latest 10-K and today's news release, all of which are available to you on our website at denbury.com. Also during the course of today's call, we will reference certain non-GAAP financial measures. Reconciliations of and disclosure on these measures are provided in today's news release.

With that, I'll turn the call over to Phil Rykhoek.

Phil Rykhoek

Thank you, Jack. As we've discussed over the last several quarters, we've been highly focused on increasing shareholder value through a combination of growing production, reducing costs and generating sustainable long-term dividend growth. So I'd like to start by kind of summarizing our progress on those objectives.

Our total production was up 2% organically on a sequential quarter basis, gains in both tertiary and non-tertiary production. Tertiary reached a new high of just below 41,000 barrels a day in this quarter on the continued response to the expansion of our Gulf Coast and Rocky Mountain EOR floods. Non-tertiary production increased primarily as a result of higher production from properties in the Rocky Mountain region as a result of recently completed wells and field optimization projects. However, even though production grew sequentially, we are now estimating our total annual production will average slightly below the low end of our previously disclosed guidance range of 76,500 BOEs per day. The largest driver of this change is lower-than-estimated natural gas sales from our Riley Ridge gas processing facility due to unplanned well downtime. Craig will cover this and other drivers of our production outlook for the second half of 2014 in his section.

Despite production trending slightly lower than desired, our cash management is doing well as evidenced by $62 million of excess cash generated year-to-date over and above capital expenditures and dividends. And we may generate additional excess cash in the second half of the year depending primarily on capital expenditures and oil prices. Our excess cash flow has been boosted by internal cost reduction efforts with operating cost continuing to decline on a sequential quarter basis, continuing a downward trend from late last year. In addition, based on year-to-date capital expenditures and reductions in our capital costs, spending on our planned 2014 projects may come in below $1.1 billion, allowing us to accelerate future capital projects into 2014. Although we still have ways to go, we're encouraged by the efforts and accomplishments we have seen thus far and feel confident that we can continue to find efficiencies and additional reductions in our cost structure. We will continue to allocate our capital on a way that we believe creates the most value for our shareholders.

On the hedging front, we've used the strength in oil futures price over the last few months to extend our hedge positions at attractive levels into the first quarter of 2016. By securing future oil prices at rates higher than those utilized in our internal long-term budget, we have improved the estimated range of future cash flow from operations that will allow us to sustainably grow our dividend over the long term. On dividends, we announced our third quarter quarterly cash dividend last week. Thus far, we've been paying them an annualized rate of $0.25 per share. But based on current outlook, we still plan to grow our dividends at an annualized rate of $0.50 to $0.60 per share in 2015. On the share buyback front, we didn't make any repurchases last quarter. And so we still have approximately $220 million authorized under that program.

While much was accomplished in the quarter, there's still much to be done to meet our long-term growth and income plans. We have a great team in place that looks forward to the challenge of unlocking the value that we see in our asset base. And with that, I'll turn the call over to Mark and Craig to give you more details on the quarter. Mark?

Mark C. Allen

Thanks, Phil. My comments will summarize some of the notable financial items in our release, primarily focused on the sequential change from the first quarter. I'll also provide some forward-looking guidance to help you in updating your financial models to reflect the current outlook for the remainder of 2014.

Our non-GAAP adjusted net income for the second quarter was $93 million, up $4 million from the first quarter, primarily driven by lower operating expenses and higher production volumes. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $314 million for the second quarter, 9% higher on a sequential quarter basis for the same reason as above and as well as lower current taxes. Although our realized oil price increased over $2 per barrel from Q1, settlements related to our fixed price swaps on roughly 80% of our oil production offset most of that increase. And the deterioration of our differentials from Q1 resulted in our net realized oil price, including hedge settlements, being down about $1.15 per barrel from the first quarter.

Our NYMEX differential weakened as expected from nearly $1 per barrel below NYMEX in Q1 to slightly over $3 per barrel below NYMEX during the second quarter. Our oil differentials declined across the board, and our Gulf Coast tertiary production, which primarily receives LLS pricing, averaged $1.15 per barrel above NYMEX, down approximately $2.50 per barrel from Q1. In the Rocky Mountain region, our Cedar Creek Anticline oil differential declined by $1.60 per barrel, selling at just over $10 per barrel below NYMEX this quarter. Thus far in Q3, our LLS and Rockies differentials have deteriorated somewhat relative to Q2 levels. And therefore, we are currently expecting that our differentials will average $3 to $5 per barrel below NYMEX in the third quarter.

Moving on to our hedging activity. Our oil hedges for the remainder of 2014 are all fixed price NYMEX-based swaps at a weighted average price of roughly $92.50. We recently extended our hedge positions into fourth quarter of 2015 and first quarter of 2016, utilizing a combination of both NYMEX and LLS fixed price-enhanced swaps in 3-way collars. Beginning with the first quarter of 2016, the average volume weighted for price for our combined LLS and NYMEX hedges exceeds our long-term oil price assumptions using our long-term model. We currently estimate that every $5 per barrel increase in our net realized oil price results in an additional $100 million of cash flow. Full details of our hedging positions are shown on our updated investor presentation that was posted to our website this morning.

On the expense side, our lease operating costs improved from the first quarter of 2014 with LOE per BOE decreasing by about 7% to just under 25 -- or $24 per BOE in Q2, which is slightly better than we had guided to. On an absolute dollar basis, our LOE was down 4% due to a decrease in workover costs, partly offset by higher utility and CO2 costs. For the remainder of 2014, we continue to expect the overall LOE per BOE to be in the mid-20s range, excluding any potential additional Delhi-related remediation expenses or insurance reimbursements. Third quarter LOE per BOE maybe slightly higher than Q2 due to workover costs related our Riley Ridge well, which Craig will discuss in further detail.

Although we have not reported any incremental charges for Delhi Field remediation expenses this year and our surface remediation efforts there are complete, there are assertions of additional third-party claims that we are unable to regionally estimate at this time. And as a result, it is possible that we could report additional costs in future periods. However, we remain in discussions with our insurance carriers and continue to believe that 1/3 to 2/3 of our $114 million expense thus far and any potential additional cost should be covered by insurance.

On to G&A expense. G&A expense was roughly $39 million in Q2 in line with our expectations and down from $44 million in the first quarter. For the second quarter, $8 million of our G&A was stock-based compensation. For the remainder of 2014, we expect G&A expense to be in the upper $30 million to mid-$40 million range each quarter with approximately $7 million to $10 million of this amount being stock-based compensation. Our depletion, depreciation and amortization rate increased $0.35 per BOE from the first quarter to slightly above $21.50 per BOE in the second quarter, primarily due to higher production without any significant reserve additions. For the remainder of 2014, we continue to expect our DD&A rate to remain between $21 and $22 per BOE.

Our effective income tax rate for Q2 was slightly below our estimated statutory rate of 38%. And we recorded a current tax benefit this quarter primarily due to the cost associated with our recent sub debt refinancing. For 2014, we anticipate our effective tax rate will be between 37% and 38% with current taxes representing between 10% and 15% of total taxes, which is down from our previous estimate of between 15% and 20% due to the tax benefits derived from our recent debt refinancing.

Moving onto our capital structure. Total debt at June 30 was approximately $3.6 billion, which was up about $90 million from March 31, with the increase primarily driven by the early redemption premiums associated with our debt refinancing. We had $445 million drawn on our $1.6 billion credit facility at June 30, down from $600 million at the end of Q1. In conjunction with refinancing of our 8 1/4% notes and the issuance of the 5 1/2% notes, we took the opportunity to turn out some of our bank debt. Based on our current assumptions for 2014 cash flows, capital expenditures and dividends, we anticipate ending the year with bank debt between $400 million to $500 million, excluding the impact of any remaining incremental share repurchases in 2014.

Interest expense net of amounts capitalized was $47 million in Q2, down roughly $2 million from Q1 due to the reduction in interest expense from the Q2 reduction and refinancing of our 8 1/4% notes with 5 1/2% notes. The refinancing reduced cash interest on our principal amount of the 8 1/4% notes by over $27 million per year. However, factoring in the incremental subordinated debt we issued and the higher interest rate on the subordinated debt versus bank debt, our net annual cash interest savings are estimated at about $17 million. If you combine this with the refinancing of the sub debt we did last year, we estimate that we will save approximately $60 million in cash interest on the face amount of the notes refinanced. But this amount is offset somewhat by the higher amount of sub debt outstanding as we termed out some of our bank debt with these transactions.

Capitalized interest was relatively unchanged from Q1 to Q2 and in line with our expectations. We expect capitalized interest to range between $5 million and $7 million for the third and fourth quarters of this year. Our capitalization metrics increased slightly as our debt-to-capital ratio was approximately 42% at the end of the quarter, up primarily due to the approximately $115 million of incremental cost that we rolled into the 5 1/2% notes that we issued in April. And our debt to trailing 12-month EBITDA was about 2.6x. Our 2014 capital budget is estimated at $1 billion plus an estimated $100 million for other items, including capitalized internal acquisition, exploration and development costs, capitalized interest and preproduction EOR start-up costs. And this is down approximately $25 million from our previously disclosed amount due to lower estimated capitalized interest and preproduction EOR start-up costs.

And now I'll turn it over to Craig for an operational review.

Kenneth Craig McPherson

Okay. Thank you, Mark. Total company production for the quarter was slightly above 75,000 barrels of oil equivalent per day. Our tertiary oil production averaged just below 41,000 barrels per day. Our tertiary oil production increased on a sequential quarter basis. Growth continued at Hastings, Heidelberg, Oyster Bayou, Tinsley and Bell Creek Fields. We did have slightly declining production at our mature tertiary properties in Delhi Field.

At Hastings, sequential production increased by about 150 barrels per day, which is slightly lower than expected due to weather-related power failure at our processing facility in the quarter. We do expect to see continued growth at these fields throughout the remainder of 2014 as the developed patterns continue to respond to CO2 injection. Also we have 2 new infill wells that will come online in the third quarter. Part of this year's capital work program at Hastings included the development and initiation of CO2 injection into 2 new fault blocks, which we refer to as Fault Blocks D and C. CO2 injection into these new fault blocks has been delayed several months to allow time to complete plugging and abandonment work. The P&As took more time than anticipated and we are just about to finish them. This few months' delay of starting CO2 injection will result in production from these new fault blocks occurring in early 2015 rather than in the fourth quarter of this year.

Oyster Bayou continued to show solid reservoir response, increasing by more than 350 barrels per day sequentially in the second quarter. This increase is due to the reservoir continuing to respond to CO2 injection, combined with optimization work that was done. We are currently developing Oyster Bayou's A-2 Zone and expect it to start contributing to production during the third quarter. As a result, we expect additional production growth in the second half of 2014.

Moving on to Heidelberg. Heidelberg Field's tertiary production increased about 280 barrels per day from the first quarter. We expect continued production growth at Heidelberg for the remainder of 2014, as the Christmas zone in West Heidelberg responds to CO2 injections and a new Tuscaloosa zone unit in East Heidelberg comes to production. Additionally, in the fourth quarter, East Heidelberg's production from the Utah zone is expected to grow as it responds to CO2 injection.

At Tinsley, production grew modestly due to favorable response from the patterns we've added there. This field is now officially fully developed and therefore, production has likely peaked at that field. For our mature area tertiary properties, production declined by 1.8% sequentially. That's less than the 2.4% decline from the fourth quarter of '13 to the first quarter of '14. We have implemented various capital projects in several of our more mature properties. And that's resulting in slightly lower decline rates. We continue to pursue opportunities to mitigate this decline further.

Let's move now to the Rocky Mountain region. Bell Creek's tertiary production increased over 500 barrels per day during the second quarter as the field continued to respond well to CO2 injections despite fluctuations in CO2 delivery volumes from Lost Cabin. Bell Creek's tertiary production recently has exceeded 1,500 barrels per day, and we continue to expect this field to be an important key driver of our anticipated 2014 tertiary production growth. Bell Creek's production growth, while good, may be somewhat lower than we anticipated in the next few months. We are currently injecting less CO2 than forecast due to compressor downtime at Lost Cabin. We have had failure of several compressor pistons and we're working with a compressor manufacturer to resolve the root issue. We anticipate having the compressors back operating later this week. The reduced CO2 injection associated with the downtime may slightly dampen the rate of production growth in the next few months.

Production from our non-tertiary assets increased nearly 600 barrels of oil equivalent per day during the second quarter from just under 34,000 in the first quarter, primarily due to production increases at Thompson Field in Texas and Hartzog Draw and Cedar Creek Anticline Fields in the Rockies. Production at Thompson Field increased by 260 barrels of oil equivalent per day on a sequential quarter basis. That's a result of equipment upgrades completed in Q1, which improved operational run times and helped stabilize gas lift and compression in the fields. We've recently drilled 4 infill wells and plan 2 more.

Production at Hartzog Draw increased nearly 250 barrels of oil equivalent per day on sequential quarter basis, primarily as a result of new wells that were put on production. So far this year, we have drilled 6 wells at Hartzog Draw. We completed 5 of them and have 1 more to go. On average, the horizontal wells we've been drilling at Hartzog have attained our predrill estimates. However, there has been more variability in the result than we expected. So consistent with our strategy to maximize shareholder value, we have elected to take a pause in our Hartzog drilling program to determine why the results have been mixed. This will enable us to improve future drilling and value creation performance.

Accordingly, we are moving a rig from Hartzog Draw to drill horizontal wells at Cedar Creek Anticline. This one has a small impact on our combined production from these 2 fields since the Hartzog wells typically have higher initial production than the CCA wells. Our Cedar Creek Anticline production increased nearly 150 barrels of oil equivalent per day during the second quarter from slightly above 19,000 barrels in Q1 as we experienced less downtime, and we completed additional wells and field optimization projects. We do expect CCA's production to be down a little in Q3, and that's due to some unexpected downtime we have experienced there thus far in the quarter. The most significant of that is related to the failure and required replacement of a large electrical panel, which has impacted the water injection of the Cedar Hills South waterflood. This repair work was completed earlier this week and water injection is now ramping back up.

Moving to Riley Ridge. Natural gas production from our Riley Ridge natural gas processing facility averaged approximately 2.2 million cubic feet per day during the second quarter and that's a 34% increase from Q1. Riley Ridge's Q2 production was lower than anticipated due to downtimes in late April and early May resulting from an outage at Williams gas plant in Opal, Wyoming. Most recently, we experienced reduced production at Riley Ridge due to lower production volumes from the 2 wells that were raw gas to the separation plant. While performing a workover on one of those wells, the coil tubing units failed, resulting in an unplanned downtime and expense. This work added to non-tertiary operating costs in Q2 and will add additional cost in Q3 -- through Q3. We're optimistic these operations have been successful and that Riley Ridge production will ramp up later this quarter and in the fourth quarter. The timing of the plant turnaround is also moved out to late Q4 or early 2015 due to equipment availability. This turnaround is expected to enhance and sustain throughput capacity of the plant.

We continue to come up the learning curve on how best to produce and process this unique, world-class reservoir at Riley Ridge. The lower Riley Ridge natural gas production has negatively impacted our annual corporate non-tertiary production estimates by approximately 1,200 BOEs per day, which drove us slightly below the low end of our estimated production range. However, because it is natural gas with relatively high operating costs, this has not had a significant impact on our estimated operating cash flows. The real significance of Riley Ridge is a few years out when it will supply CO2 to our growing EOR developments in the Rockies. Overall, looking at our company-wide production, we now expect total production to average slightly below the low end of our estimated production range of 76,500 BOEs per day we provided back in November.

With that, let's move on to lease operating expenses. We are starting to see positive results from our initiative to focus on cost and value creation. Our lease operating expense per barrel of equivalent production decreased nearly $2 in Q2 from Q1. Operating cost on our tertiary properties averaged $26.57 per barrel in the second quarter, and that's a decrease of over $0.60 per barrel from the first quarter level. The sequential decrease in quarterly LOE per BOE primarily reflects increased production and a reduction in well workover activity in both our operating regions, partially offset by higher CO2 and power costs. Total workover cost during the second quarter returned to levels in line with or better than historical levels. And this is in part due to focusing on solving the root cause of our well problems. We anticipate our overall 2014 per BOE operating cost to remain in the mid-20s.

Let's turn to our capital program. Halfway through the year, we spent about 45% of our capital budget. We are beginning to see positive results from our organization's focus on cost savings and value creation. And that's started to show up in our capital spending. We have seen some reductions in our drilling cost and some facilities-related cost reductions as well. Most importantly, cost savings discussions are increasingly becoming part of the everyday culture. Accordingly, our 2014 total combined capital program is expected to come in under the $1.1 billion budget. We are evaluating options to accelerate some future capital projects into 2014 to potentially utilize this available capital.

Let's move now to our CO2 supply and transportation operations, which in general, are performing well and fulfilling our growing demand. In the Gulf Coast region, we produced slightly under 800 million cubic feet per day of CO2 from Jackson Dome during the quarter. We were able to reduce our usage of CO2 in the Gulf Coast by over 100 million cubic feet per day compared to Q1, and this reduction is intentional. As part of our cost savings and value creation emphasis, our teams look for ways to optimize CO2 utilization. We need CO2 injection targeting areas of the reservoirs with the largest amount of oil demanding to be recovered. The teams found intervals taking CO2 that had little oil left in them. As a result, the [indiscernible] has already swept intervals, which reduced our CO2 usage without materially impacting oil production. Increasing CO2 efficiency is significant and it should lower future capital costs associated with developing our CO2 production capacity.

In the Rocky Mountain region, we received roughly 60 million cubic feet per day of CO2 from our combined sources at LaBarge and Lost Cabin. We purchased an average of approximately 70 million cubic feet per day of CO2 that was captured from industrial sources in the Gulf Coast region for use in our operated fields in the region during the second quarter. Our man-made CO2 supply is expected to get a boost when Mississippi Power Plant is complete in the next 12 months. There is a possibility we will receive some CO2 sooner than 12 months out as Mississippi Power Plant starts to ramp up production. Our combination of natural and man-made CO2 sources gives us the ability to manage our CO2 supply to help ensure our floods receive the necessary supply.

And with that, I'll turn the call back over to Jack.

Jack T. Collins

Okay. Thank you, Craig. Roxanne, that concludes management's prepared remarks. Can you please open the call up for questions?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Jason Wangler with Wunderlich Securities.

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

Curious, the CapEx thing sounds really interesting as far as being able to see some lower costs. I just wanted to maybe get color on the fact. Are you seeing just lower cost overall? And so your ability to either see a lower CapEx budget this year or possibly bring in some more work, is that just simply seeing lower cost on a per unit basis? Or however you want to characterize it versus necessarily pushing things out? Because in the past, we've had that discussion. But it looks like now, it's just actually cost savings.

Kenneth Craig McPherson

The cost savings we're seeing are currently in some of our drilling. We're seeing reduced cost in the drilling of our Hartzog Drill Draw wells and our CCA wells. We're also seeing a reduction in some cost of our facilities. A big driver of that is usually twofold, one is looking for better ways to do it. Also we are pressing our suppliers for improved cost and leveraging our scale as well as our standardized approach. We are looking for -- and so that is creating some space and some room that we are looking to bring some 2015 programs into '14 to utilize some of that freed-up money.

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

Okay, that's great. And then just obviously you're already kind of generating at least a little bit of cash flow on top of the dividend and obviously operations. What's the thought with -- assuming that hopefully that can continue if oil prices stay up here, is that just going kind of towards the debt, as Mark talked about it a little bit, where the debt would be at the end of the year? Or is there anything else that you'd look at specifically to use that in the coming quarters before we get into '15?

Phil Rykhoek

Yes. Of course, that's always the swing because that's kind of the plug number with bank debt there. So currently -- well, as Craig said is we've kind of hesitated to say we're lowering our budget per se. But it does look like we're coming in less than what we thought. We may try to accelerate some projects. If we do that then actually in the second half, we'll probably spend our cash flow. But if there is a swing, we'll likely use it for debt. Of course, we always do have the stock repurchase program still there and the option to move capital around a little bit.

Operator

And our next question comes from the line of Pearce Hammond with Simmons & Company.

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

I wanted to dig a little bit into the guidance. So before today, you guys had been guiding to the low end of the range, which is that 76,500 BOE per day. And that was driven by getting a little later start, as I remember, on the CO2 flood at Bell Creek, and then also because of Riley Ridge. Now you're going to go below that number. Are you talking about going below that number by the 1,200 BOE per day that Craig outlined and as far as the impact from Riley Ridge?

Phil Rykhoek

Well, that is the single biggest contributor. And obviously, if you take 1,200 off the midpoint of our original range, you're below the 76,500. So that's the single biggest one. And then the second one, you appropriately identified. Bell Creek, as we mentioned earlier in the year, has always been running a little bit behind due to the delay in getting the interconnect done on the [indiscernible] pipeline. It's grown nicely in the second quarter, but we do see just a little concern what could happen in the third quarter with this -- the issues that were on the compressors. I would probably say Bell Creek is likely to be at least a few hundred, maybe several hundred barrels a day below the original forecast. So long story short, we're probably going to be more than 200 below the low end of the range, probably several hundred at best. But there is still some variability there.

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

That's helpful. And then following up from Craig's prepared remarks, could you expound a little bit upon what you don't like that you're seeing at Hartzog Draw and why you're reallocating that rig away from there?

Kenneth Craig McPherson

Yes. So at Hartzog, we've drilled 6 wells, we've completed 5. Of those 5, 1 is above expectations, 2 are basically at expectations and 2 below expectations. The one above expectations is way above, it was over 1,000 barrels a day IP. The worst one was almost completely watered out, so tremendous variability. So why? Well, we have an idea as to what's causing the low performers. In fact, specifically, we think it's a high permeability streak that's connected to the nearby waterflood and is flooding out the zone. We've got some ideas how we can isolate that. And so we're taking a pause to figure out how we eliminate or reduced exposure to the downside and frankly, how we get some access to the upside. We want to understand better where that 1,000 barrel a day -- what drove that 1,000 barrel a day well. So we think we've got a chance to do better than our average. And so we're taking a pause to pursue that. We've got some work planned actually in a couple of weeks on the well that was 100% water. We think we can isolate the interval that's watered out and we think that well will respond nicely. So we're just doing a bit of evaluations. We think we can improve the overall portfolio at Hartzog. And so that's the reason for the pause. The nice part is that we had a place to go send that rig. We're doing really well at CCA. It's not a far jaunt to take that rig over to CCA for a bit and draw some nice wells there while we're doing some diagnostics at Hartzog. We fully intend to go back to Hartzog with an optimized plan.

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

And then Phil, one last one for me. As you peer out into 2015, how do you see non-tertiary oil production trending next year?

Phil Rykhoek

Well, I hesitate to get into 2015 too much because, as you know, we give guidance in our Analyst Meeting this fall or November. But in general, we're struggling to keep non-tertiary from declining, and so it probably will. I mean, I hesitate to give a number yet, but we do have some positives at Hartzog and the drilling CCA has helped. But on general, mostly it feels it's going to decline.

Operator

And our next question comes from the line of Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Some of my questions have been asked already. But I was hoping to drill down a little bit on, I guess, in prepared comments, we heard this a couple of times, evaluating options to accelerate future capital projects into '14. Is that just -- is that sort of just a wish list of to-do projects that you have planned for '15 that you're going to accelerate? Or what kind of color can you provide on what we might expect from that?

Kenneth Craig McPherson

Well, we're developing that list now, it's a variety of options. Things like maybe drilling an additional well or 2 at Thompson, some additional infill at Hastings, possibly accelerating some work in our mature fields, also could ramp up some a bit of work at CCA. We may also be able to do some work on optimizing some of our other floods. It sets a light variety, but it's that type of looking at our existing programs and just moving some '15 plans into '14. Maybe on a scaler, we're -- this is probably talking $25 million to $50 million. That's about the scale of what we're talking about, if that helps.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay, that is helpful. And then lastly, you gave some comments on Delhi. But should we assume a kind of a steady decline from that field going forward? I mean, how much is just the field having peaked versus the new approach of not being able to maybe flood it optimally like you would've otherwise?

Phil Rykhoek

Well, we don't expect Delhi to change too much in the third quarter. It did slip just a little bit, but it's kind of been kind of flat really for the last 6 months. We don't expect that to change. Do keep in mind there is a payout coming. And we think that's going to occur probably early fourth quarter or -- and so that's going to be the biggest change. So you'll see a drop, and then post-payout, I think going in 2015, we actually would expect it to grow a little bit. But you're going to see -- keep in mind, there's a dip coming in the fourth quarter.

Operator

[Operator Instructions] And our next question is from the line of Richard Tullis with Capital One.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Phil, just looking -- or Craig, looking at the guidance for the second half of the year, I mean, how do you see the actual oil production trending? I know you did about 71,000 barrels in 2Q. Should we expect maybe a 2,000 barrel quarter-over-quarter increase in oil production growth for the second half?

Phil Rykhoek

You may have that in the fourth quarter. I think third quarter is likely to be pretty low growth. We know some of the issues that Craig went through already. So we expect fourth quarter to grow. Third probably is going to be very modest growth.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Okay, that's helpful. And just lastly for me, what parameters are you looking for in order to resume the share repurchases? I mean, where does that rank -- share repurchase program rank in your priority now when you consider maybe drilling acceleration, et cetera?

Phil Rykhoek

Well, that's always a tough question to answer. I mean, this all depends on share price, oil price, leverage and options, I guess. So we just continue to evaluate it on a regular basis both with management and with the board. So it really depends on the relationship of those items. We are -- at this point, we probably would be borrowing the money to do it, other than the free cash we generated in the first part of the year, which, as you can debate, we perhaps went for the earlier share repurchases as a part of it. So we are conscious of our leverage, and so we do definitely take that into consideration.

Operator

And our last question comes from the line of Natasha [indiscernible] with Tuohy Brothers Investments.

Unknown Analyst

The first question is can you provide any more color on your evolving cost reduction strategies, particularly in modular facility design and electricity consumption?

Kenneth Craig McPherson

We continue to pursue all avenues of cost reduction. That's really across every spectrum of our business from our capital -- design of our capital facilities, how we drill our wells to lease operating expense.

Phil Rykhoek

Yes. On the facilities you asked, I mean, we actually -- that's probably, I don't know, 75%, 80% down the road. You'll see some of that at Webster. It will be a distributed facility rather than a central facility. So you'll see some of the first benefits of it at Webster. Of course, that really is mainly a 2015 expense as far as out-of-pocket spending, but that's ongoing. We're continuing to tweak that. But I think you'll see the first benefits of that next year.

Unknown Analyst

Great. And then you discussed a little bit about Bell Creek production. Has any additional production been shut in to help increase the field pressure there?

Kenneth Craig McPherson

No, field pressure is good there. We're above miscibility pressure there or it would maintain that, so, no.

Operator

And at this time, there are no other questions in queue.

Jack T. Collins

Okay. Roxanne, before we end the call, let me cover a few housekeeping items. On the conference front, several members of our management team will be participating in investor conferences over the next few months. Also for your calendars, we plan to hold our annual Analyst Day here in Plano on Monday, November 17. Please check the Investor Relations section of our website for details on these presentations, including the webcast and the slides. Lastly, you should also mark your calendar for our third quarter 2014 results, which we plan to report on Wednesday, November 5. We will hold our conference call that day at our usual time of 10:00 a.m. Central. Thank you all again for joining us today, and have a great day.

Operator

And ladies and gentlemen, this conference will be made available for replay after 12:30 p.m. today running through September 6, 2014, at midnight. You may access the AT&T Executive Playback service at anytime by dialing 1 (800) 475-6701 and entering the access code 292663. International participants may dial 1 (320) 365-3844. That does conclude our conference for today. Thank you for your participation and for using AT&T Executive TeleConference service. You may now disconnect.

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