Gulfport Energy Corporation (GPOR) Q4 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Fourth Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I'd now like to turn the conference over to your host for today, Mr. Paul Heerwagen. Sir, you may begin.

Thank you, operator, and good morning. Welcome to Gulfport Energy's fourth quarter and year end 2013 earnings conference call. I'm Paul Heerwagen, and the order of the speakers on today's call are Mike Moore, interim Chief Executive Officer, President and Chief Financial Officer; Ross Kirtley, Chief Operations Officer of Ohio; Rob Jones, Vice President of Drilling of Ohio; Mark Malone, Vice President of Operations of Ohio; Ty Peck, Managing Director of Midstream; and Kerry Kroll [ph], Controller. Also on the call are Stuart Maier, Vice President of Geosciences; and Steve Baldwin, Vice President of Reservoir Engineering. During this conference call, the participants may make certain forward-looking statements relating to the company's financial conditions, results of operations, plans, objectives, future performance and business. 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 on the company's filings with the SEC. In addition, we may make references to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted to our website. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with this earnings announcement. Please review it at your leisure. In connection with the Chief Executive Officer search, the board has retained Preng & Associates to assist the board in its search. Preng & Associates specializes in energy and has a reputation for being the world's most accomplished energy executive search firm. Preng intends to conduct a nationwide search to look both externally and internally for candidates that bring expertise and exceptional management credentials. In addition, the board has engaged Preng to advice in the search for directors with industry background and technical expertise to fill the existing vacancies and potentially expand the board. Currently, no specific timeline has been set out on this process, but the board does anticipate conducting a thorough and timely search for all positions. At this time, I'd like to turn the call over to Michael Moore.

Thanks, Paul, and thank you all for joining us this morning on our call. 2013 was an important year for the company. Gulfport exited 2013 with record company production of nearly 28,000 BOEs per day, representing over a 300% growth year-over-year. Throughout the year, we continued the development of the Utica Shale, increasing our rig count from 2 to 7 to accelerate our drilling of this transformational asset. On the Midstream side, in our Utica acreage, we ended 2013 with 2 wells producing and minimum gathering and processing infrastructure in place, and at year end, our Midstream partner had over 220 miles of pipe on the ground and today has nearly 600 million cubic feet of processing capacity online. In terms of take away, by recognizing early that firm transport was going to be the key to success for producers, Gulfport was a first mover and has already successfully locked in 500 million cubic feet per day of take away out of the basin at attractive rates. Early on, we invested in the necessary services via our vertical integration activities, and as we see the activity of surrounding operators heating up and their rig count in the Utica increasing, we believe the fact that Gulfport has locked in quality services at attractive prices will pay significant dividends. Lastly, during 2013, we increased the number of employees by approximately 60% and continued to grow already experiencing an additional 15% growth year-to-date. We continue to add staff in all areas of the business, but the majority of our new employees have joined our operations staff and they exhibit a wealth of shale knowledge. 2013 was a year that held many challenges that come with operating in a new emerging play, but we also had many accomplishments. We also recognized that we needed to continue to build the organization and position the company for 2014 and beyond. At year-end 2013, our total proved reserves were 14.02 million barrels of oil and 146.45 billion cubic feet of natural gas or 38.43 million BOEs, up 177% from 2012. In addition, third-party engineers have issued a probable reserve report estimating 15.94 million barrels of oil and 170.62 billion cubic feet of natural gas or 44.38 million BOEs of probable reserves. The reserve growth in the lower 48 was driven by our success in the Utica and shareholders should continue to see significant reserve growth as we further develop the assets through the drill bit and obtain more production history. Looking ahead to 2014, we've reaffirmed our previously announced production guidance of an estimated 50,000 to 60,000 BOEs per day. When compared to our actual 2013 production, this suggests a total company production growth of 343% to 432% during 2014. In anticipation of this growth, we have recently made several key management additions. First, Ross Kirtley has joined Gulfport as the Chief Operating Officer of our Ohio activities. Ross is an accomplished executive with a broad-based background in the energy business in both public and private sectors. Since joining Gulfport, Ross has continued to improve the quality of the processes and procedures in place in Ohio and focuses on building a qualified and knowledgeable team to execute on our activities. I will now turn the call over to Ross to discuss in detail our Ohio operations.

Thanks, Mike, and good morning to each of you. When I began my duties as Chief Operating Officer in Ohio in late September, we identified 2 priorities that I devoted my immediate attention to. The first was to reemphasize and enhance our focus on workplace safety and environmental stewardship. The second priority was to develop engineering teams who could focus on drilling wells more efficiently and completing wells with the goal of maximizing EURs. I am pleased to report that we have made significant progress in these areas. We have focused on hiring individuals who have extensive shale knowledge and experience. And with that in mind, we are pleased to have brought Rob Jones and Mark Malone into the Gulfport team as Vice Presidents of Drilling and Operations, respectively. Both Rob and Mark have over 45 years’ experience in their professions and bring a wealth of expertise to the team. Rob brings with him the experience of taking part in the drilling of over 2,000 horizontal shale wells in the last 5 years, running up to 45 rigs in the Barnett, Haynesville and Eagle Ford, and has arguably drilled more share wells than anyone we have come in contact with. Rob's initial focus has been to emphasize our commitment to safety and environmental stewardship, reduce cycle times at the drill bit and identify near-term cost reductions by leveraging his experience from his previous work. We are also pleased to bring Mark Malone into our team as Vice President of Operations. Mark brings with him his experience in designing and executing fracture stimulation and managing completion and production activities. Prior to joining Gulfport, Mark was the Senior Asset Manager in the Marcellus and was responsible for all fracture stimulation and completion activities for a 24-rig program. Mark's immediate focus was to build a team who could execute completion activities efficiently and effectively. Rob and Mark are continuing to build their teams and have added in excess of 40 very talented employees thus far. The Gulfport operations staffs' motto is to plan the work and work the plan. We implemented a strategic planning efforts to assess and enhanced all activity in the field on a daily basis, which includes production, drilling metrics, completion metrics, costs incurred and almost every other aspects of activity occurring for that particular day in Ohio. Our new data management process is allowing us to analyze our performance metrics and costs on a very granular level. The ultimate goal of this process is to provide information to the operations staff so they can make a concerted effort to reduce costs across the board and increase efficiency in all areas. As a management team, we emphasize the duty of every employee and contractor to identify cost-reduction opportunities and bring them to their manager's attention. This process accesses the hub of the wheel and it connects all departments and identifies how each department can work together to achieve lower costs and increase efficiencies. Rob is in the process of enhancing our drilling designs by implementing state-of-the-art drilling software programs that will allow him and his staff to maximize the drilling efficiency. I'll now turn the call over to Rob to discuss the initiatives he has implemented with his team on the drilling side of operations.

Thanks, Ross. Our first initiative was centered on building out an organizational structure allowing every member of our team to focus on their strengths and tasks at hand. Drilling superintendents are to focus on drilling and utilizing their expertise at the drill bit. To accomplish this, the goal is to make the responsibilities of the superintendent outside of the drilling wells minimal. In addition to the drillers, engineers are expected to focus on the development plan and path of engineering each well. We've brought the engineering process in-house by hiring multiple engineers along with the current staff to originate the engineering of the directional planning, casing design, drilling fluids, cement design and many other responsibilities to create a more managed program and higher level of engineering. We have also identified multiple processes to evaluate and benchmark performance, enabling us to assess where our current successes and failures occur in the drilling process. Our data management software gives us the ability to break down the drilling process into 30-plus line items providing granularity and easy access to the data. Through this, the team will create a technical limit, which is comprised of a number of metrics that sets the goal for every phase of the drilling. The goal is to create a composite well of the best of the best metrics from our drilling history. The engineering team can then transfer the positive metrics to all drilling operations and develop new processes to enhance the deficiencies. Emphasis is first placed on consistency of adhering to the drilling plan and then turn our focus toward efficiencies to reduce cycle times. The drilling team has identified several areas where we're concentrating on to make meaningful steps toward lowering our well cost. First, we will be testing slimming the hold down to 7 7/8 inches. This process has been successful in many mature shale plays. Casing size is not effected which creates no changes in the completion and production phases. Reducing the hole size enables you to increase rates of penetration while reducing costs of materials such as drilling fluids, cement and [indiscernible]. Second, the drilling team is implementing a performance [indiscernible] project associated with a rig mobilization. In the past and even currently, Gulfport has lacked efficiency during pad to pad moves. We have identified this deficiency and are implementing the processes to correct it. This will allow our drilling operations to quickly return to the job of drilling. Lastly, we're in the process of enhancing our rig fleet. Our drilling efforts are directly correlated to the equipment and personnel we contract. Having fit-the-purpose drilling equipment allows us to drill faster and reduce cycle times. In addition, continually seeking the best wellsite personnel will only enhance our operations. The fewer days we spend on each location is the major contributor to our efforts in reducing drilling costs. In summary, our goal on the drilling side is to first create consistency in our current operations at the drill bit. We have realigned existing personnel on the drilling team allowing for an increase of focus to be applied, to executing the well designs and effectively reducing costs everywhere possible. Executing the technical limits will allow a best approach and let the team identify and focus on the areas of deficiency. Once the group enhances the positive and eliminates the negative, cycle times will decrease and costs will follow. Thank you for your time today.

Thanks, Rob. You've just heard Rob describe initiatives he has put in place to drill wells faster and cheaper by defining key performance metrics and measuring performance against those defined metrics. Mark has been and continues to focus on a detailed analysis of the previous completion activities. His staff is in the process of evaluating previous frac designs versus production in an effort to establish the optimum frac design for each of the 3 product corridors. Mark and his team's focus is to ensure that all CapEx devoted to completion activities will yield the best-performing wells in the Utica. I will now turn the call over to Mark to tell you about his team's current focus and efforts.

Thanks, Ross. We believe what is measured is managed and we therefore, established a number of metrics to track all aspects of our well completion and work associated -- work-associated costs. As an example, Gulfport has set an internal goal to be able to retain and complete 4 or more fracture stimulation stages per day. Therefore, we track stages per day along with all reasons for noncompliance in order to implement the changes needed to meet our goal. Time from reg release, fracture stages per day, cycle time for deposit flood drill out and time required to turn the well to sales are all separate phases in the completion process that we benchmark. We will continue to measure the data and work towards reducing our time on location in order to reduce our costs. Additionally, we have implemented well reviews, postmortem studies in order to identify areas for cost savings or cycle time reduction. It is also our objective to leverage our activity to attain the best vendor pricing and track vendors for a long-term contractual commitment. Efficiency to some degree can be obtained through repetition and the consistencies that are seen by working the same crews. Our team continues to track completion metrics relative to production results to confirm the techniques being applied are yielding the best results. We've learned a lot over the last year, but we know we have a great deal more to learn. We're working towards identifying the most efficient fracture stimulation treatment for each producing window be it dry gas, wet gas or condensate. Fracture stimulation optimization is currently the top priority for our engineering staff. Along with this goal, we continue to work towards identifying the optimal spacing regimes in each phase corridor. Internally, we're in the process of monitoring the production of the wells on which we have tested down spacing in the condensate window, and are currently drilling our Darla pad, which will test multiple spacing regimes in the wet gas window. In addition to our own data, we are sharing information and learning from other operators that we've signed CAs with. With our past planned downspacing activity and our peers testing different spacing regimes as well, we look forward to 2014 results to support and determine the optimal spacing regime in the play. That's about it: Safety, no spills, planning, metrics and hopefully optimized [indiscernible] , to create the highest well EUR at the lowest cost we can master. Thank you for your time today.

As you can see, we remain focused on adding value for each dollar that we invest and believe the practices being put in place by Ross, Rob and Mark. We'll pay dividends as we continue development of this play. On the Midstream front, in November 2013, Gulfport hired a Managing Director of Midstream, Ty Peck. Ty has a considerable amount of experience in the negotiation, execution of short and long-term commercial gathering and processing contracts. Ty has developed a commercial strategy that secures the transport of Gulfport's products out of the basin while being strategic and selective in the projects we choose to participate in. I will now turn the call over to Ty to provide more detail of Gulfport's effort on the Midstream side of our business.

Thank you, Mike. In 2013, we quickly realized that the continued development in the Marcellus and the emergence of the Utica were creating an environment where flow assurance would become increasingly difficult, firm transport out of the basin would be required and a strong institutional knowledge of the North American gas infrastructure to optimize our portfolio would give us a competitive advantage. Today, we're happy to announce that we have recently entered into an arrangement with BP North America Gas and Power where they will act as Gulfport's natural gas marketer. Tapping into BP's experience throughout North American energy markets, specifically the Northeast, will allow Gulfport to enhance our flow assurance, optimize our firm transport and ensure a holistic approach as we have believed is required for the Appalachian basin as it continues to evolve the North American energy markets. I do believe it's worth reiterating that under this current arrangement with BP, they are contractually committed to flow assurances for Gulfport production. With the results achieved on the dry gas window and our continued development in the wet gas and condensate windows, we quickly secured in the second half of '13 firm transport out of the basin that we believe were very attractive firm terms. Today, we are pleased with the progress of securing a total of 500 decatherms a day, giving us access to both Midwest markets beginning in the spring and Gulf markets later this year. We continue to actively seek additional firm transport for our longer-term production profile, but our lower-cost transport in addition to another approximate 100,000 decatherms a day in firm sales has allowed us to be more selective in the projects coming to the market which have costs and commitments that are quickly escalating. Additionally, Gulfport has elected to participate in reversal of [indiscernible], which has the potential for us to secure firm transport at rates and timing which best fits our current needs. As for gathering and processing, I am pleased to report that MarkWest remains ahead of our drilling activity. With 600 million a day of processing capacity online between Cadiz and Seneca and another 400 million coming online between now and the early part of third quarter '14, MarkWest has thus far achieved the necessary milestones to execute on our targeted in-service date and we feel confident they will be able to gather and process our liquid-rich gas coming online. In addition, since year end, MarkWest has brought on [indiscernible] to further enhance the fractionation services and we look forward to the benefits we will see from the expansion of such going forward. We also anticipate the condensate stabilizer coming online by the third quarter of '14 and we're currently working diligently to secure markets [ph] that captures the value of such product in the marketplace. As Gulfport moves rigs further east to the dry gas window, MarkWest has acquired and began clearing the right of way for the 2014 drilling plans. In fact, last week we met with MarkWest senior management and they expressed confidence that their current progress will enable them to have pipeline to all scheduled pads in time for our production. In December, we announced Blackhawk Midstream, a company in which Gulfport owned 50% interest, agreed to sell its equity interest in his Ohio gathering. As an anchored tenant in this system, we were able to negotiate an option to participate at a 40% interest in the buildout of certain gas gathering systems and the condensate stabilization facility. Gulfport focuses on value creation in all areas of our business and this option was a unique way we created value by being an early entrant into the play. We recently closed this transaction which resulted in approximately 90 million net to the Gulfport's interest. And it's worth noting that at the time of this closing, Gulfport had not invested any capital in the system. In summary, with the majority of this infrastructure in place, the ability to capture attractive firm transport and sales and the recent announced arrangements with best-in-class marketers, we are well positioned to deliver in '14 on the Midstream side.

Thanks, Ty. You can see that Ross, Rob, Mark and Ty are adding significant value to our existing staff, and when combined with our current personnel, position Gulfport to execute and deliver on our 2014 goals. Now let's move on to our other assets areas starting with Canada. We are pleased to report that Grizzly's first SAGD facility at Algar Lake commenced steam generation through the plant and well pad facilities in December 2013. Steam has now reached all the well pad facilities as Grizzly plans to circulate steam through all 10 wellbores for the next several weeks after which first bitumen production is scheduled to begin late in the quarter. Temperatures and pressures within the well pairs are behaving as expected, and as you will see in our presentation posted to the website this morning, while the plan is still in the warm-up circulation phase, we are already seeing oil come back for the initial well pair injected earlier than expected. Grizzly and Gulfport are excited to reach the milestone of first bitumen at the first SAGD facility. Grizzly had an active winter drilling season. In the first quarter of 2013, Grizzly completed a 29 well delineation drilling program in May River. An initial 12,000-barrel a day development application was filed with the Alberta Energy Resources Conservation Board in December for the eastern portion of the May River lease. Currently, a 2D seismic program is underway to more fully define the development area of the remaining 660 million barrels of contingent resource. Similar to Utica, Grizzly is focused on take away and securing attractive prices for its product. We recognize price realized for the bitumen in the oil sands is a key economic factor for the expected returns and projected economics. With this thought in mind, Grizzly is developing a robust infrastructure to support rail movement of crude to the U.S. Gulf Coast. Construction of a 15,000-barrel per day rail transloading facility at the Windell terminal in Alberta has begun and is expected to be completed and ready for operations by the end of this quarter. At the Paulina terminal, along the lower Mississippi River, Grizzly has filed the development permits and begun the engineering design work on a 40,000-barrel per day barge transloading facility. At year end, Grizzly received a third party resource support from GLJ reflecting 16.75 million barrels of crude reserves attributable to our 25% interest in Grizzly's Algar Lake SAGD project. On top of that, we also had exposure to 51 million barrels of probable reserves and 778 million barrels of best estimate continued resource net to Gulfport's interest. Remember, 2/3 of Grizzly's current leasehold remains unexplored. In Thailand, our exploration well tested at noncommercial rates. During drilling, the well flowed gas with rates as high as 20 million cubic feet of gas per day. However, no acceptable sustainable rate was established. Now turning to Southern Louisiana. In South Louisiana, during 2013, we drilled a total of 40 wells, completing 36 best [ph] producers with 2 wells drilling at year end, 1 waiting on completion and 1 non-productive. In addition, we performed 150 re-completions. Currently, we are running 2 rigs and are drilling ahead in our third and fourth wells of 2014. I will now turn the call over to Kerry Kroll [ph], Gulfport's Controller, to cover the financial highlights during the fourth quarter and full year 2013.

Thanks, Mike. During the fourth quarter, Gulfport generated approximately $90.7 million of EBITDA, $39.7 million of operating cash flow and $24.3 million of net income. As a result, in 2013, Gulfport generated approximately $388.4 million of EBITDA, $170.8 million of operating cash flow and $153.2 million of net income. Our fourth quarter net income includes a loss from hedge ineffectiveness of $16.9 million and a gain of $54.7 million in connection with our equity interest in Diamondback Energy. Adjusted net income comparable to analysts' estimates, a non-GAAP measure was $4.5 million or $0.05 per diluted share. Our earnings per share for the quarter was negatively impacted by higher-than-anticipated G&A, largely attributable to an increase in stock-based compensation, higher interest expense and lower oil realizations for the quarter. During the fourth quarter of 2013, production averaged 15,668 BOE per day, which was an increase quarter-over-quarter of 28%. For the year ended December 31, 2013, production averaged 11,283 BOE per day, which was a 51% growth in production over 2012. Allocated by field, fourth quarter production breaks out to be 10,701 BOE per day from the Utica, 5,889 BOE per day from Southern Louisiana and 78 BOE per day from the Niobrara overrides and other miscellaneous areas. Our production mix for the fourth quarter was 55% oil and natural gas liquids and 45% natural gas. Our full year production mix consisted of 64% oil and NGLs and 36% natural gas. Average realized prices before the impact of derivatives for the quarter were $96.35 per barrel of oil, $3.45 per MCF of natural gas and $56.70 per barrel of natural gas liquids. Our blended realized price before the impact of derivatives for the fourth quarter was $57.82 per barrel of oil equivalent and for the full year 2013 was $70.99. Lease operating expense for the fourth quarter was $8.4 million or $5.45 per BOE and $26.7 million or $6.48 per BOE for the full year. G&A was $7.9 million or $5.18 per BOE for the quarter and $22.5 million or $5.47 per BOE for the full year. Depreciation depletion and amortization expenses during the fourth quarter totaled $37.1 million or $24.17 per BOE and $118.9 million or $28.87 per BOE for the full year. In terms of capital expenditures, in 2013, we invested a total of $454.2 million, which excludes Gulfport's portion of Grizzly activity and Utica leasing activity. Our liquidity position remains strong. As of December 31, 2013, we had $459 million in cash and $299 million of total debt outstanding and were completely undrawn on the revolving credit facility which has a current borrowing base availability of $150 million. Moving on the guidance. We continue to anticipate first quarter production to be relatively flat to the company's 2013 exit rate of 27,780 BOE per day. January production averaged approximately 21,745 BOE per day. And today, February production has averaged 25,771 BOE per day. And in the last week, it has averaged 26,678 BOE per day. Currently, we have line of sight to 10 wells that were recently completed and will be hooked into sales over the coming week. Estimated capital expenditures during 2014 remain unchanged, anticipating $675 million to $725 million associated with our drilling plan and $225 million to $275 million on leasehold acquisition in the Utica Shale. For 2014, we estimate full year unit LOE to be in the range of $2 to $3 per BOE, full year unit transportation, processing and marketing to be in the range of $2.50 to $3.50 per BOE. Full year production tax to be in the range of 4% to 6% of expected revenue, full year unit G&A to be in the range of $1.25 to $2.25 per BOE, full year interest expense to be in the range of $4.5 million per quarter, and we estimate our DD&A rate to be in the range of $21 to $24 per BOE. At present, for the remainder of the first quarter of 2014, we have fixed price locked in place for 4,000 barrels of oil per day at a weighted average price of $104.75 and approximately 91 million cubic feet of gas per day at a weighted average price of $4.02. Gulfport has begun solidifying its hedging program for the coming years, locking in fixed price swaps for 2015 of 175 million cubic feet of gas per day at a weighted average price of $4.08, and January through April of 2016 on average of 105 million cubic feet of gas per day at a weighted average price of $4.04. We feel very good about our gas hedging position and the recent increase in gas prices has allowed us to layer on additional positions, which we believe goes a long way towards derisking our current and future cash flows. I'll now turn the call back over to Mike for his closing remarks.

Thank you, Kerry. In October 2012, Gulfport contributed [ph] Permian basin interest to Diamondback Energy IPO. Since the IPO, the Diamondback stock price has increased 270%, trading near $65 per share yesterday, and at this price, Gulfport's current ownership has a value of $218 million. Announced -- with our earnings announcement yesterday afternoon, Gulfport is currently evaluating strategic alternatives with respect to certain oilfield service entities in which we own an interest, an S-1 has been submitted on a confidential basis to the SEC in connection with these interests. Gulfport may choose to pursue an initial public offering of these interests later this year subject to market conditions. We continue to be active on the leasing front in Utica. Gulfport has entered into a binding letter of intent with Rhino Resources to acquire their 5% working interest in our shared position, equating to 82,000 net acres and approximately 1,000 BOEs per day. Including this transaction, Gulfport added 18,080 net acres since our last reporting period, increasing our exposure to this world-class resource. In 2013, we grew production 60%, and this year with current guidance, we anticipate total company production growth of over 300%. Our company is significantly changing, and not many of our peers are planning to experience this type of growth trajectory. I hope that today we have adequately conveyed our commitment to establishing a culture of execution and our dedication to deliver on our planned 2014 activities. I thank you again for joining us for our call today, and we look forward to answering your questions.

Operator, please open up the lines for questions from our participants.

[Operator Instructions] Our first question today comes from the line of Neal Dingmann from SunTrust.

Say, Mike, just a question on the type curves, I was looking at your -- the new slide deck that's out and you've updated those, it looks like your EUR estimates are still the same, but you've now updated both and given a 2-year sort of average and 30-year average out there. Can you comment on, again, where some of these wells -- you mentioned some of the wells now how long they've been on, how much they differ -- either for you or Mark or the guys, if you could comment how they differ some of the wells before or after your choke management system and if there's a big difference there on these wells.

Mark, do you want to take that one?

Yes, absolutely. We're watching these wells closely. Each day, I mean, we watch pressures on each well, and we're managing the pressures on each. We had some very good condensate wells come on as of late, and we're very encouraged about those results.

I might add, Neal, that we're very encouraged by the continued performance of these wells against the type curve. So we certainly don't have any data at this point to suggest that we need to adjust type curves. The -- both the condensate and the wet gas production plots seem to indicate that those type curves are still holding in there.

Okay. And then just on your production, you guys reiterated for first and then for total. Mike, I don't know how much you can say about either wells behind pipe or I know some of the peers, like Gulf or Chesapeake and some of these others have mentioned, about how much is restricted because of lack of capacity out there. I was wondering if you can maybe hit both those things back. Are you still -- you or again, for Mark, if you're holding some wells back because of lack of infrastructure and if that will come on as infrastructure continues to improve? And then just, again, because just looking at sort of the behind pipe or some of the wells that potentially could come on soon.

So I'll take part of it, and Mark can hop in here, too. But first of all, please understand, I can't speak for our peers, but Gulfport is not restricted in any way on how we're producing our wells. So we have plenty of takeaway, plenty of capacity. We don't have wells shut in, waiting on pipeline. So our wells are not restricted. And secondly, we have an inventory. As Keri mentioned in her scripted comments, we have 10 wells completed that we're going to be bringing on very shortly.

That's correct. March should be very good month for us again. As Mike mentioned, we've got 10 wells about to come on. If you looked at the fourth quarter last year, we averaged about 11 BOE per day -- 11,000 BOE a day -- per day. And we ended in the quarter -- or the year rather with an exit rate of about 28,000. So we've done this before, so this isn't new to us, and we're confident that we'll make that number in March based on those 10 wells that are coming on. They're all fracture stimulated at this point and in the final phases of completion.

And Mark, how big a factor was weather sort of the last quarter versus kind of what you and Rob have seen historically? I know you've operated in that area in past years. I know other operators have mentioned it. Again, how big a factor was that? And are you continuing to see any hang-up because of weather?

Neal, this is Ross. I'm going to answer that. Obviously, we try to prepare for the weather. We know that Ohio is known for cold winters. We didn't plan for the coldest winter in 33 years necessarily. So we had a lot of days that we spent that were 11 degrees -- minus 11 degrees. We had multiple issues with that with frozen wellheads, ice plugs in flow lines. I think 1 day, we had 3 drilling rigs and had the brake [indiscernible] stuck to the drum works. So yes, we did experience a lot of problems with the weather. We did -- I think the first snap, we learned from it, and I'll let Mark give us a little bit more color here in just a second. But we did make some improvements. In the second snap, we didn't have near as much product go offline as we did in the first one. I might add, too, Neal, that we experienced some problems getting some product out of the line due to some frozen hydrates in the transport lines out of the field. Some stuck pigs that were trying to remove those frozen hydrates. And so we did have some problems getting product out of the field. But we're not using that as an excuse. We're continuing to execute at the highest level we can, and we feel pretty confident that we're going to exit the quarter hitting our exit rate that we've published. Mark, you want to...

I think the big takeaway from that is we did have 2 severe cold snaps, the first being worse, of course, but the second cold snap toward the end of January was just about as bad. The good news is that the changes that we made in the first cold snap, it kind of revealed some holes in our armor. We identified a number of areas where we had freezing issues and freezing potential on pipelines and facilities. So point being, we've made a lot of changes reflected in the second half. So when we had the second cold snap, the severity wasn't near as bad and had less effect on us quite frankly.

Our next question comes from the line of Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: A couple of questions. On the rig count that you have, when you look forward to 2014, Mike, how do you think you spread that between your 3 different areas? And is some of the ramp in the gas area going to be related to/dependent to what the Darla pad suggests when you get results?

Well, I'd say, first of all, we've been pretty public about saying that this year, the expectation is that we're going to have 4 rigs operating in the wet gas window, 2 in the dry gas window and 1 in the condensate window. That's the general distribution of rigs. Now we don't have any rigs right now in the dry gas window. They'll move over there April 1. We're giving MarkWest time to get all that infrastructure in place. So we -- as far as down spacing is concerned, certainly, as we learn the answers from the Darla pad and we understand more down spacing, which is not -- we're not going to know until probably August or September, it could cause us to change the way we push our wells together, but it's not going to directly affect our drilling activity. It's just going to affect how close we push the wells together. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then I guess, a related question. Since most of the activity has been in the wet gas window, the -- from a production profile or commodity mix standpoint and the way you at least forecast in your completions, how should that transition, say, from the first quarter commodity mix to the fourth quarter as we look at the growth?

So we entered this year about 50% dry gas, Ron, and as we move through the year, you're going to see us ramping up that dry gas component. And we will exit the year probably 70-plus dry gas. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then of the remaining -- of the 30% of liquids, can that be plus or minus evenly split between oil and NGLs? Or will NGLs start to outweigh that as well given the Utica growth?

I think for this year, a good way to look at what's left is 50/50. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then one last one for me. On the lease acquisitions, the Rhino purchase is, obviously, just the remaining interest in your original Utica position. The 10,000 acres of incremental leasing, is that grassroots leasing? Is that the kind of thing you've talked about of trying to add 10,000 acres a quarter? And is that located more in the dry gas window where it seems your focus has been primarily because of availability?

That's exactly right, Ron. It's greenfield leasing around our existing acreage blocks, and generally, it's in the dry gas window.

Our next question comes from the line of Biju Perincheril of Jefferies.

Great update in terms and especially with -- on molding out the management team in Utica. And I was just wondering where are you in terms of adding, and are you now at a state where you have sufficient technical folks for the Utica development? Or are you still adding to that team?

Biju, this is Ross. We're still adding to the team. We have some people that we've hired that we're waiting for their arrival. We're still upgrading in every area that we can. We're bringing some well tenders on and completion engineers on as well. So we're continuing to upgrade and continuing to add. But I'd say we're probably middle of the fourth quarter on getting there.

Okay, great. And then I was wondering on down spacing, the Boy Scout wells, that's, I guess, been online for some time now. How are those wells compared to some of the wider-spaced walls?

Well, the Boy Scouts -- so the Boy Scouts, we drilled a well 600 feet away, and then we drilled another well 800 feet away. What we found on the Boy Scouts -- and we're really not seeing any communication, first of all, so let me answer that question. But secondly, operationally, particularly in the condensate window and I think you see it reflected in our type curves, we're seeing better performance from the newer wells than the older wells. We are flowing the newer wells in the condensate curve. So I think that we're seeing no material difference from our condensate wells, generally, to answer your question.

Okay. And do you have any planned down space tests in the condensate window this year? Or are you waiting for the Darla pad before you do that?

I don't think -- and these guys can jump in if this isn't correct. But I don't think we have any additional down spacing planned in the condensate window. Our next down spacing ideas will come from the wet gas window.

Yes, and I was just going to add that we had the Darla project that everybody's talked about, and it's going to define a lot of the spacing issues for us we hope. We also have some contractual agreements in place, partners that are looking at various down spacing. We're going to learn from our peers as much as anything. So the down spacing or the spacing question is paramount to our operations, and we understand that. So it's something we're focusing on and again I hope that the Darla project will shed some light on the spacing.

Got it. And then a question for Rob on the drilling side. You'd mentioned some of the new efforts that you're putting in place, and I was wondering where costs today are and what you're targeting in terms of savings from some of those efforts.

Currently, our targets on the costs are -- we're targeting about $9.5 million for a total layout [ph] fee cost, which our internal goals on the drilling side are going to be about $3.5 million for our standard 8,000-foot lateral. Certainly, the costs currently are above those numbers, and we have some ways to go. I think we've -- we're gathering the people and the equipment to reduce our cycle times and be able to lower those costs.

Biju, this is Ross again. I just wanted to kind of give you a little bit more color on the staffing question. I thought you might want to know this that we think with the staff we have and that we have coming on board here in the next couple of weeks that we'll be able to fully execute a 10 to 12-rig package. So just thought you might want to know that.

Just a follow-up on the well cost, the $9.5 million I assume that's an average for the program. How does that vary in the dry gas versus as you go farther west in the condensate window?

Well, in the dry gas, it'll certainly be a little more expensive because they're a little deeper, a little high pressure. We certainly will be running the intermediate casing almost in, I would say, in almost in all cases just due to the nature of the well and the safety issues. We certainly -- under those circumstances, they would certainly be higher.

Our next question comes from the line of Tim Rezvan of Stern Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: The first question I had is on your year-end reserves number that was reported. It looked a little conservative to me. I was wondering if you could talk about how many wells were booked and what assumptions were made by the reserve auditors for those reserves.

Yes. This is Steve. This is a new play, and the third-party engineers are still collecting data in all the windows. Longer production history is needed, which will give us a more accurate story of -- for our wells and all the windows. But what we are seeing today, we're very encouraged by what they're giving us, what we're seeing today. And the PUD, your PUD question, we had 20 booked PUDs for 2013 -- at the end of '13 in the Utica. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: And then looking out to the 2014 growth, I appreciated the color on March production. As we think out to the rest of the year, it's still a very steep ramp from first quarter to full year. With the 7 rigs you've had running now for quite a while, how do you see that trajectory through the year? Do you see kind of a smooth ramp?

It's going to be pretty linear, Tim. But you should expect -- from first quarter to second quarter, I think, the expectation would be probably about a 45% growth, and then you're going to see a pretty linear ramp quarter-over-quarter beyond that. I'd say second quarter to third quarter, you can think in terms of 50% and then third quarter to fourth quarter, 40%. So you're to see some pretty steep ramp as we accelerate our program out there. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. And is it safe to assume that you have more dry gas contribution in that third and fourth quarter number?

That's exactly right. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. That's great. And then one last one for me. The color on the Darla pad has been helpful. If we step back, are there -- what are the biggest goals -- the biggest questions you're looking to get answered on that pad. Is it just down spacing? Or what are the other major objectives that you're pursuing there?

This is Mark Malone. The big objective, of course, is spacing and that's priority, but along with that, we're also looking at fracture design parameters, stage spacing and perforation design, that sort of thing. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. And do you think that maybe in August-September time frame we can learn what you've learned?

That's a good target time, yes.

Our next question comes from the line of Jason Wangler with Wunderlich Securities.

Just curious, over on the JV with Rice, when do you think you'll start seeing stuff over there? I think, Mike, you were just saying that, obviously, the eastern side with dry gas will start to kind of ramp second half. Is that kind of the thought process there as far as the -- your 2 rigs going that way?

That's exactly right. And we're currently drilling in our JV acreage right now.

Okay. And then just with Grizzly, I appreciate the color on that, and first production coming on, it's great to hear. I mean, do you see as -- could you maybe just an idea of the production profile of that? I mean, obviously, is there a ramp-up period to get to the full capacity of the site, approximately how long that takes, things like that? Just curious of kind of how to look at that as we go throughout the year.

Yes. Generally, Jason, the rule of thumb is 10 to 12 months to ramp up to full production, and it's a fairly slow but linear ramp over those 10 to 12 months. So that's generally what it takes.

Our next question comes from the line of Marshall Carver of Heikkinen Energy Advisors.

On the Rhino acquisition, is that part of the acreage budget? Or would that be part of some separate acquisitions budget?

No, it's part of our announced budget for the year.

And do you have the number of wells completed or put onto sales for January, February and your expectation for March?

No, we're currently not talking about that.

Okay.

We -- go ahead.

I guess, final question would be on -- so your -- your oil realizations were a little bit lower when I was modeling for Q4, but NGLs were higher. Do you have any color on the first quarter for both of those? And is there any -- would the NGL realizations be even higher because of the rise of propane prices? Or what color can you give us there?

This is Ty Peck. Yes, we've seen in the fourth quarter the rising of the NGL realization, and we believe that will continue into the first quarter. With the MarkWest infrastructure, we've been able to take advantage whether that's domestic demand or international. So we'll see that going on into the first quarter. And long term, I think we're still going to be in that 45% of WTI as well for the NGL pricing.

Our next question comes from the line of Leo Mariani of RBC Capital Markets.

Can you talk to gas price dips a little bit here? It looked like gas prices were maybe a little bit weaker in the fourth quarter. Can you give us an indication kind of what you're seeing and what your expectations are here in 2014?

Yes. We're seeing a lot of -- basically, supply is going to be coming on in the '14, so we'll see some pressure on gas prices. But that's why we've taken out the firm transport that we did, and therefore, as we get into '14 and this firm transport optionality comes on. We'll be able to firm up our pricing arrangements on those paths [ph].

Okay, got you. And I guess, could you guys tell us how many Utica wells came online in the fourth quarter of '13?

There were 14 wells that came on in the fourth quarter.

Okay. Now that's helpful. And I guess, just in terms of reserves, just trying to get a sense of what you guys have booked here in terms of the wet gas and condensate wells. You guys had indication of kind of what the per well EURs were on any of those?

No. Leo, the problem is we've got so many different wells with so many different lateral lengths and so many different production histories. It's really not relevant to talk about a per well number yet. We're just not far enough into the play. I think when we get more history behind our belt. And I think you need to keep in mind, in 2013, we went back to existing locations and drilled some of our PUDs. In 2014, we'll be drilling new locations, and we'll get a lot of offsetting acreage. So I -- it's just -- it's early -- it's too early to talk about per well numbers.

All right. I guess, in terms of acreage acquisitions, obviously, it looks like you did a good chunk of the budget here. Could you talk at all just kind of about pricing that you're seeing in terms of purchases in kind of the different windows?

Well, I'd say you've seen a lot of prices being -- a lot of high prices being paid lately for larger acreage blocks, which is certainly appropriate. Obviously, a lot of folks recognize the value of this play. I would say, as far as the greenfield leasing is concerned, we really haven't seen -- we've seen some pressure, but that -- those prices aren't translating down to the greenfield leasing. We are being very aggressive, I can tell you, and we're continuing to pick up as much as we possibly can. So we expect to continue to pick up acreage out there for the rest of the year.

Our next question comes from the line of Brian Velie of Capital One.

All of my questions have been answered at this point.

Our next question comes from the line of David Beard of Iberia.

I wanted to see if you could give us any more color relative to either wells flowing or wells tied in here for the first couple of months of the quarter, either in January or February, an exit rate.

I don't have an exit rate to give you today, but I think you can probably do the math based on January. I just -- I think you have to keep in mind, we've got 10 wells that are ready to come online here very shortly, and that's going to get us to our average production that we gave for the quarter. And I think the relevant point here to keep in mind is that's in spite of this record cold weather that we have. So I think, don't miss that we haven't changed our production guidance for the first quarter in spite of the challenges with the weather.

And then a follow-on relative to take-away capacity, did you break that down between the different commodity types, gas, condensate and NGLs? Or could you throw us in the ballpark if you haven't?

That's all gas.

Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers.

I got 3 questions, hopefully, they're all pretty quick. First one was, unless I missed it, I didn't see any published specific well results for the fourth quarter '13 completions as you've done in the past, and I wondered if this is a change of practice going into the future.

You're exactly right. It is a change of practice where we feel like we're at the point of the play now where we have a lot of activities going on, and we simply can't continue to talk about well-by-well information. So you're going to hear us talking about activities in the different windows of the play in averages. But so it is a change of conversation about how we talk about the play.

My second question was do you have a target time period in mind for the CEO decision.

I don't think there's any specific time period that they've allocated. They want it to be a logical, thoughtful process. And I think they're willing to take as long as they need to find the right person.

And my last question is going to the oil services. First of all, when you had the discussion earlier, you talked about high grading your rigs and completion crews and so forth. The press release also mentioned doing something with your owned oil services. I was wondering if these are 2 interrelated events or is there something different behind the motivation to find other alternatives for the owned oil services.

No, there's no motivation except value creation.

Thank you. And ladies and gentlemen, this does conclude our question-and-answer period. I'd now like to turn the conference back over to Mr. Paul Heerwagen for any closing remarks.

Yes. Thank you, operator. I believe that concludes this morning's call. A replay of the call will be available temporarily through the company's website and can be accessed at gulfportenergy.com. Thank you for your time and interest in Gulfport Energy today. This concludes our call.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may all disconnect. Have a great rest of your day.