Ladies and gentlemen, welcome to the Diamondback Energy third quarter earnings call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session, and instructions will follow at that time. If anyone should require operator assistance during the conference, please press star then zero on your touchtone telephone. As a reminder, today's conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Adam Lawlis, investor relations. Mr. Lawlis, please begin.
Thanks, Janine. Good morning, welcome to Diamondback Energy's third quarter conference call. We have prepared PowerPoint slides to supplement our call today, and they can be accessed on our website at www.diamondbackenergy.com. Representing Diamondback today are Travis Stice, CEO; Teresa Dick, CFO; and Russell Pantermuehl, Vice President of Reservoir Engineering. We also have Paul Molnar, our VP of Geosciences. During this conference call today, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. During our call today, we will reference certain non-GAAP financial measures which we believe provide useful information for investors.
We include reconciliations of those measures to GAAP in our earnings release. I will now turn the call over to Travis Stice.
Thank you, Adam. Welcome, everyone, thank you all for listening to Diamondback's third quarter 2013 conference call. Since our last call, we've issued several press releases highlighting our one-year anniversary as a public company, surpassing the 10,000 barrel a day production milestone and our first Clear Fork test in Andrews County and our guidance for 2014. As Adam mentioned, we've updated the company presentation on our website, I'll refer to a couple of those slides during my comments this morning. The third quarter again marks improvements across essentially all aspects of Diamondback's performance as we continue to make significant progress on lowering drilling and completion costs, reducing our operating expenses, and testing additional horizontal benches while continuing to rapidly increase production.
We've now drilled over 38 miles or 200,000 feet of horizontal lateral sections since the beginning of our horizontal development program a little over a year ago, our execution continues to improve to what I feel is a leadership position within the Midland Basin. Also, the cash margin per BOE Diamondback generates is best among our peers due to the more oily nature of our production mix and the dramatic reduction we've made in our operating expenses. While it was just a few weeks ago when I was offering my last operating update discussing our Clear Fork test, today I'll provide an update on more of our drilling activities in addition to discussing our strong quarter. First of all, I'm very excited about the early performance from a 5,000-foot lateral Middle Spraberry Shale test in Midland County that we participated in as a non-operator partner.
The well had a peak 24-hour initial production rate of 733 BOEs a day, of which 90% was oil from an electric submersible pump out of the Middle Spraberry Shale. This is the second significant test in the Spraberry interval following the original test in the Lower Spraberry completed several months ago. The Spraberry interval not only is one of the more continuously deposited shales across the Midland Basin, but also contains among the highest measured original oil in place compared to the other shale members. If you refer to the slide in our company presentation on page seven, you can see how both of these Spraberry wells are exceeding our 600,000 BOE Wolfcamp B type curve for Midland County, that's why we're excited.
On slide five and again on slide 16, encouraged by this Middle Spraberry test, we've now added 180 horizontal locations to reflect this new bench in the Middle Spraberry, substantially increasing the resource base our shareholders are exposed to and further validating our recent purchase of the underlying mineral rights exposed to in this area. This early test furthers our belief that multiple benches will ultimately develop across our acreage. Lastly, to help clarify any confusion on the Spraberry nomenclature, we have included a cross-section on slide six, which shows both the Middle and Lower Spraberry Shale and how the Spraberry thickens as you move east across our acreage. Staying in Midland County, we've completed the Spanish Trail 501H, our longest lateral to date in this county, at approximately 9,000 feet for less than $8.5 million.
This is one of the best wells we've completed, now at 38 days has flowed naturally longer than any other horizontal well that we've put on production. The Spanish Trail 501 had a peak naturally flowing rate of 1,033 BOEs a day and has produced for the last 30 days over 24,000 barrels equivalent, flowing in excess of 800 BOEs a day. We will not kill a well to put it on artificial lift that continues to flow back so nicely just to generate a higher 24-hour IP rate. However, when we do put the well on artificial lift, we typically expect a significant uplift from the well's peak flowing rate. On slide eight, we annotate this uplift as an artificial lift effect. Finally, in Midland County, we have two other wells to highlight that are producing favorably.
The Spanish Trail 36-2H had a 24-hour IP of 1,069 BOEs a day from a short lateral, and the Spanish Trail 36-3H well had a 24-hour IP of 934 barrels a day, also from a short lateral. These wells were 94% and 89% oil respectively and are both on gas lift. As a reminder, Diamondback Energy owns the mineral interest on all of these wells, significantly enhancing returns and cash flows. Shifting further north in Andrews County, our first horizontal Wolfcamp B well remains encouraging, now reflecting a 30-day peak rate of 440 BOEs a day from a previously reported peak 24-hour rate of 613 BOEs a day. This well was drilled with a short 4,000-foot lateral due to lease geometry. When normalized to a 7,500-foot lateral, the peak 24-hour rate would have been approximately 1,100 barrels a day, and the 30-day rate would've been approximately 815 barrels a day.
Referring to Slide 8, you can see that the production from this well is above the 600,000-barrel Wolfcamp B type curve as well as almost after 90 days. We also remain encouraged by our initial horizontal Clear Fork test, which had a peak 24-hour IP rate of 611 barrels a day. This well was drilled and completed for $6.8 million for a 7,500-foot lateral. Looking ahead at additional development drilling, we feel we could decrease development cost meaningfully, especially in multi-well pad development mode and utilizing a fit-for-purpose drilling rig. We will wait several more months to gain additional production data to generate our investment type curve before drilling an offset well. Once we're comfortable with predicting reserves for the Clear Fork, I'll communicate accordingly.
When we evaluate our performance using preliminary data for all of our horizontal wells across all counties, we remain at or above our average type curve projections. As a reminder, we've guided towards 550,000-650,000 barrels for a 7,500-foot lateral. We're currently running four horizontal rigs, one in Upton and two in Midland County, with a fourth horizontal rig set to begin testing our recently acquired acreage in Martin County this month, with results expected during the first quarter of 2014. As recently outlined, we envision a fifth rig coming in the second quarter of 2014, and based on these results, may consider adding a sixth rig later in the year. Turning to our quarterly results. 3Q13 production averaged 7.4 thousand BOEs a day, almost double last year's levels, and do not reflect any of our recent acquisitions.
The production ramp we expected from horizontal wells has continued, and we entered the fourth quarter producing over 10,000 barrels a day. Current production is about 10.5 thousand barrels a day, and we envision exiting the year possibly close to 12,000 BOEs a day, but have offered no official guidance. Instead, we've introduced 2014 production guidance of between 15,000 and 16,000 BOEs a day, trying to stay away from quarterly guidance. Our focus is on sequential growth with a clear eye on operational efficiency, as shown by our performance during this year. Our operation team continues to improve performance to a level we believe is among the best in the Midland Basin. Our 7,500-foot laterals averaged approximately $7.2 million, down from $7.6 million in the previous quarter. For the three 7,500-foot lateral wells that were drilled during the quarter, total depth was reached on average in 14 days.
We've drilled our first test well, where we used a cheaper, smaller, and faster-moving vertical rig to drill and set deep intermediate casing to roughly 9,000 feet before the bigger horizontal rig arrives to drill the curve and lateral portion of the well. We estimate this saves between $150,000 and $200,000 per well and will reduce our cycle time by seven days. While this is still in the testing phase, we estimate we could apply this strategy to roughly 25% of our wells, helping to further reduce costs and drilling more wells with fewer rigs in 2014. Our first two-well pad location has been drilled and completed with two approximately 5,000-foot wells for a combined total cost of $10.5 million-$11 million.
We're still finalizing costs and allowing our accounting system to catch up with these costs and have a few operations left to perform, but early cost results certainly look encouraging with per-well cost below $5.5 million. We also used the zipper frack technique, where we conducted simultaneous operations on both wells, which not only improves efficiency in operations, but we think also improves fracture stimulation effectiveness. We're currently drilling our second well on our second two-well pad, and we anticipate drilling over 50% of our wells next year on multi-well pads and will soon shift to three-well pads. With these impressive cost results, we've decreased our well cost guidance for 2014 for a 7,500-foot lateral to a range of $6.9 million-$7.4 million in 2014, and from $7.5 million-$8.5 million in 2013 as we previously announced in our 2014 guidance conference call.
Now looking at expenses. We've changed the method used to report our LOE to be more consistent with our peers, including ad valorem taxes as part of production taxes. Previously, we'd included ad valorem taxes as part of lease operating expense. We made this reclassification and will report this way going forward and will restate historicals over time. Corporate overhead, previously reported as indirect LOE, is now included as part of lease operating expenses. 2013 guidance has been adjusted to reflect this reclassification. If you have any questions on this, please call Adam Lawlis following the call and we can help out. Our third quarter total LOE per BOE decreased 21% to $7.27 per barrel, down from $9.16 in the second quarter of 2013, after giving effect to the reclassification.
We've now achieved four consecutive quarters of double-digit declines in LOE, which are now down over 50% from this same period last year. The quarterly details of this dramatic reduction in LOE are laid out on slide 14. Additionally, this reduction in LOE has yet to benefit from our recent purchase of the Midland County minerals, which, as we've explained, have no associated LOE with the production. Combined with our much higher price realization due to our higher oil content, Diamondback's cash margin per BOE is now among the highest of our peers, and we expect to rise further in the fourth quarter as the minerals acquisition is fully incorporated. Again, please see our updated guidance and results, which breaks out the contribution from these minerals, as we don't think everyone understands our mechanics here. It's safe to say, though, that it's making our good results even better.
With these comments complete, allow me to turn the call over to Teresa.
Thank you, Travis. Our net income for the quarter was $14.6 million, or $0.33 per diluted share. Net income for the period included a non-cash loss on commodity derivatives of $1.7 million. Excluding the non-cash loss and the related income tax effects, our adjusted net income was $15.6 million, or $0.35 per diluted share. Revenues for the third quarter totaled $57.8 million, a 27% increase as compared to second quarter 2013 of $45.4 million. Our average realized prices before the effect of hedges was $84.67 per BOE, an improvement of approximately 12% when compared to $75.70 per BOE for the prior quarter. Our average realized price, including the effect of hedges, was $79.96 per BOE, compared to $74.27 per BOE for the prior quarter. EBITDA for the quarter was $47.7 million, or $69.82 per BOE.
Our EBITDA growth over the prior quarter was driven by increased production, strong realized pricing, and decreasing operating costs during the quarter. Turning to our costs, lease operating expense was $7.27 per BOE as compared to $9.16 per BOE in the second quarter of 2013, a 21% decrease. As Travis mentioned earlier, these metrics have been adjusted, reclassifying ad valorem tax out of LOE and into our production and ad valorem tax line on our income statement for all periods presented. Our general and administrative costs came in at $3.11 per BOE. This is at the low end of our guidance of $3 to $5 per BOE. Our current hedge positions through 2014 have been laid out in our earnings release. We continually assess our hedging opportunities, and we will continue to layer on additional hedges as our production grows.
In the third quarter of 2013, we generated $42 million of cash flow, or $0.94 a diluted share. We spent approximately $84.9 million. This is excluding the previously announced minerals and Martin County and Dawson County acquisitions. This spend includes approximately $78 million for drilling and completion, $3.5 million for leasehold acquisitions, and the remainder for infrastructure and facilities. Our accumulated spend for our drilling and completion, infrastructure and facilities for the nine months ended September 30th, 2013, is approximately $193 million. This excludes acquisition spend. We are on track to be in line with our annual capital guidance of between $290 and $320 million. During the quarter, we raised a total net proceeds from debt and equity offerings of approximately $618 million. This includes $450 million aggregate principal amount, 7.625% senior notes, which are due in 2021.
Our liquidity position remains strong, with approximately $53 million of cash on hand at September 30th, 2013, and an undrawn revolver with $225 million of availability. With that, I'll now turn the call back over to Travis for his closing remarks.
Thank you, Teresa. To summarize, I'm proud of the third quarter results as we again demonstrated our ability to reduce total well costs, reduce drilling cycle time, reduce our operating expenses, and continue to ramp our production. We're extremely excited about the early results from a test in the Middle Spraberry zone in Midland County, and we've increased our inventory accordingly. Our cash margins during the third quarter were almost $70 a barrel, and I believe we're delivering results and returns to our stockholders that are among the best in the Midland Basin. On behalf of the board and employees of Diamondback Energy, I would like to thank you for your participation today. This concludes our prepared comments. Operator, please open the call to questions.
Thank you. Ladies and gentlemen, if you would like to ask a question, please press the star, then the number 1 key on your touchtone telephone. If your question is answered or you wish to remove yourself from the queue, you may press the pound key. The first question is from Ryan Oatman of SunTrust. Please go ahead.
Hi, good morning, guys.
Morning, Ryan.
Obviously, a solid first rate from this Middle Spraberry Shale. Can you discuss the prospectivity that you see of that interval across your acreage and where you see it working across the leasehold that you've got there?
Yes, Ryan. As I mentioned in my prepared comments, this Spraberry interval is one of the more continuous shale deposits across the Midland Basin. Specifically to our acreage, certainly everything in Midland County looks extremely good. Also similarly, the assets we've recently acquired in Martin and Southern Dawson also look very prospective in the Spraberry intervals, as well as about half of our acreage in Andrews County, that northeast piece. Really excited about that, and those 139 net locations we've added are predominantly located in those three counties.
Okay, thank you for that. What's the depth difference between the Middle and Lower Spraberry, and do you feel like the two are definitely separate zones?
It's about 400 feet between. The question is, are they separate zones? We think they are. Certainly, they've been deposited separately. I think we as an industry will still need to prove that the fracture between one doesn't interfere with the other. At this point, we're really confident that they're separate and distinct intervals.
Okay, thank you for that. Then one more from me, I'll hop back in the queue. You talked about a $70 a barrel cash margin. What would that number look like on your acreage were you on the minerals?
Ryan, I don't have that in front of me. I'm going to have to get back with you on that. If we handle it during the call, or we can come up with it during the call, I'll circle back with you.
Sure. Thank you.
As a reminder, if you would like to ask a question, please press star then the number one key on your touch-tone telephone. The next question is from Eli Kantor of IBERIA Capital. Please go ahead.
Hey, good morning, guys.
Hey, Eli. How are you this morning?
I'm doing well. Just a question on down-spacing prospectivity within your acreage position. A couple of your peers, Pioneer and Laredo, have had success testing tighter densities than what was previously guided to. Curious if you have any plans to test densities that are tighter than 160 acre spacing within your footprint in the near future?
Yeah, all of our development to date has been at that interlateral spacing of about 850 feet. We're in the process here in the next quarter of tightening that down-spacing to an interlateral spacing of what, Russell, about 600 feet?
About 660 feet between wells. The test we're doing on our Spanish Trail acreage in Midland County, those wells will be drilled in the fourth quarter, so we'll probably have results in 1Q of next year.
Okay, thanks. That's all I have.
The next question is from Jeb Bachmann of Howard Weil. Please go ahead.
Morning, everyone. Just a quick question from me on stack laterals. I noticed you talked about testing stack laterals in the Middle and Lower Spraberry next year. Any idea if you're going to try that in some of the Wolfcamp zones next year on your acreage?
Yeah. Our next stack lateral test is going to be in Section 42, where we own about 47%. We've participated in a stacked lateral that's already been drilled. The lower lateral is in the Wolfcamp B, and the upper lateral is in the Lower Spraberry well, or Lower Spraberry, and even though it's offset about 300 feet. Those wells are scheduled to be fracked at the end of this month, then we'll probably have results on that in 1Q of next year. As it pertains to testing and stacking in other intervals, we just need to really assess what our inventory looks like in these other intervals, especially with the addition of these successful Lower Spraberry and Middle Spraberry tests as we go into 2014, look for us to provide additional color on that as we crystallize our plans.
Okay, great. One last one from me. I noticed Pioneer talked about Wolfcamp D wells in their release yesterday. Just wondering if you guys had any plans to try and drill that target on your acreage or if you're focused on the other intervals at this point.
Well, certainly we remain focused on the intervals where we've put the drill bits, it's hard to ignore a well that's 20 miles from you that tested over 3,000 barrels a day. I'm looking at a cross-section now that Paul provided me last night that has that same decline interval across our acreage base there in Midland County. Pretty exciting information.
Great. Thanks for the color, Travis.
As a reminder, if you would like to ask a question, please press the star then the number one key. The next question is from Mark Lear of Credit Suisse. Please go ahead.
Good morning. Just wanted an update on the timing of the testing in Martin and Dawson and what you guys will be targeting up there.
Yeah, good question. As I mentioned, this fourth rig that's arriving will be testing the Wolfcamp B in Martin County. Next month, actually, we'll spud that well, might get it spud this month. That's where our initial focus will be is, both in Martin and Dawson County, we'll test the Wolfcamp B. Then, of course, we'll adjust plans as we go forward and understand different horizons, because we'll always put the drill bit in the intervals that we think generates the highest rate of return for our stockholders.
I guess just as you're thinking about bringing on a sixth rig late in 2014, how does that rig count look in the mineral rights? Or how many rigs will you be operating there in Midland?
The initial guidance that I offered was two horizontal rigs on our operated piece, and the non-operated piece was going to have one horizontal rig. Our intent will be to always try to maximize the minerals because it generates such exceptional returns. We'll look for opportunities to drop a third rig in there, and whether it stays in there continuously or it just goes in there and when we have a window where we think we can accumulate enough frack water to accelerate, we'll look at doing that as well. Mark, I also want to remind, even though I said the possibility of a sixth rig arriving late next year, there's really two ways to accelerate activity. One is to accelerate through just adding more rigs, and the second is to accelerate by drilling more wells with the same rigs.
I think you've seen us historically demonstrate continued reduction in cycle times. If this first test that we did, where we're bringing up, typically, a vertical rig in to drill the deep intermediate section, that could materially change our cycle time as well. We're going to look at accelerating both ways, but I think there's a distinction there when you look at the amount that we can increase our cycle times.
Great. I guess, is there an opportunity to pick up the working interest on those mineral acres that you don't have right now?
We look at all kinds of opportunities, Mark Lear, here in the Permian. Obviously, where we own the minerals, it makes a great story to have the working interest as well too. I don't comment on any acquisitions that are currently in progress, or analysis that are in progress.
Got you. Thanks a lot.
I would now like to turn the conference back for any further remarks to Mr. Travis Stice, Chief Executive Officer.
Well, again, thanks for everyone participating in today's call. I know it was early, I know I talked to some of you guys late last night and saw some releases really early this morning. I know a lot of you on the calls had a late night and early morning. I appreciate your continued interest in Diamondback Energy's story. If you've got any questions, please reach out to us using the contact information we've provided. You guys have a great day, and we'll talk again soon. Thank you very much.
Ladies and gentlemen, thank you for your participation in today's program. This does conclude the presentation, and you may all disconnect.