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PetroQuest Energy, Inc. (NYSE:PQ)

Q4 2012 Earnings Call

February 28, 2013 9:30 a.m. ET

Executives

Matt Quantz - Manager, Investor Relations

Charles Goodson - Chairman, CEO, and President

Bond Clement - CFO

Analysts

Ron Mills - Johnson Rice

Tim Rezvan - Sterne Agee

Curtis Trimble - Global Hunter Securities

Amir Arif - Stifel Nicolaus

Jason Lazarus - Intrepid Capital

Operator

Good morning, and welcome to the PetroQuest Energy 2012 Year End and Fourth Quarter Conference Call. All participants will be in listen-only mode. (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Matt Quantz, Manager of Investor Relations. Please go ahead.

Matt Quantz

Thank you. Good morning, everyone. We would like to welcome you to our fourth quarter and year end conference call and webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO and President; Todd Zehnder, COO; and Bond Clement, CFO.

As you’ve come to expect, we would like to make our Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest business, which are not historical facts are forward-looking statements that involve risk and uncertainties. For a discussion of such risks and uncertainties which could cause actual results to differ from those contained in these forward-looking statements, see Risk Factors in our annual and quarterly SEC filings, and in the forward-looking statements in our press release. We assume no obligation to update our forward-looking statements. Please also note that on today’s call, we will be referring to non-GAAP financial measures, including discretionary cash flow. Historical non-GAAP financial measures are reconciled to the most directly comparable GAAP measures in our press release included in our Form 8-K filed with the SEC today.

With that, Charlie will get us started with an overview of the quarter.

Charles Goodson

Good morning. During the fourth quarter, we produced 8.9 Bcfe or approximately 96 million cubic feet of gas equivalent per day. The 96 million cubic feet equivalent per day was comprised of approximately 75 million cubic feet of gas, 1500 barrels of oil and 2000 barrels of NGLs. Our fourth quarter 2012 average daily liquids production increased 41% over the comparable 2011 period and was the fifth consecutive quarter of production growth.

Moving on to our full year results, we produced 34 Bcfe or approximately 93 million cubic equivalent per day, which was 13% higher than our 2011 production rate. Our 2012 average daily production of 93 million cubic feet equivalent per day was comprised of approximately 75 million cubic feet of gas, 1400 barrels of oil and 1500 barrels of NGLs. The 2900 barrels of liquids per day was a 13% increase from 2011.

Before going through our operations details, I’d like to discuss our 2013 plans which were provided to the market during our 2013 guidance press release a few weeks ago. In that release, we outlined the capital budget which stated approximately 35% lower than our 2012 capital spend. However, it’s important to note that when factoring in our joint venture, our $80 million to $100 million capital budget essentially becomes a $110 million to $130 million program. Even with this reduction in CapEx, we are forecasting production growth of 6% (inaudible) if any, small capped E&P companies that can be this flexible while delivering this type of performance. This speaks volumes for the calibre of our assets and teams we have in place as well as our promoting capital structure benefitted by our long term joint venture.

In addition to our capital and production guidance, we announced that we were moving into the second phase of our Mississippi Lime program which will be shooting at 3D seismic survey, our various acreage positions. We believe that by combining this – the production history and well results from our 2012 program with 3D we will significantly improve our geologic and reservoir model. We expect this post-3D understanding in Mississippian Lime reservoirs will greatly enhance our ability to identify future drilling locations and generate more consistent results.

This strategy is part of the plan we put in place in 2011. That plan called for testing each of our three distinct areas by drilling 12 to 15 wells and then following up with 3D shoot and field study. We implemented a similar strategy when we entered the Woodford and saw what’s combining production history the 3D study can do for development program. Our initial pre-3D horizontal Woodford wells had EURs of approximately 2 Bcf per well and took 40 days to drill. Today with the benefit of 3D our EURs have risen to an average of 5 Bcf per well and we are consistently drilling wells in under 20 days. With 3D we are able to stay in section 98% of the lateral and are able to approve – avoid minor faulting that can steal frac energy or potentially serve as a conduit to excessive water production. We would not consider drilling projects in the Gulf Coast, Gulf of Mexico and Woodford without fully integrating 3D into geologic and reservoir model. We believe that we are able to substantially reduce the variability of our well results and costs in the Mississippi Lime with the 3D integration.

There are 12 to 15 rigs active near our three acreage positions and we will be able to access most of well data production history through our consortium and will therefore be able to enhance our best practices, well and completion designs as they improve.

So to summarize our initial Mississippian Lime results support the need to invest additional capital required to obtain 3D and we would not do it if we did not believe in the resource potential of this trend. For example, reviewing range resources Mississippian Lime presentation, its horizontal phase mirrors our phase 2 plans where they acquired 3D to maximize results. We’re confident that our shareholders will be rewarded if we invest the additional time and capital needed to better understand this complex yet promising well trend.

Quickly touching our operations, in Oklahoma, our Tulsa team continues to deliver excellent results and recently initiated production from six operating Woodford wells. This set of wells averaged – achieved an average maximum 24 hour gross rate of 3700 Mcf and 200 barrels of NGLs or 4900 Mcfe. Two more wells are in the early stages of production and appear to be as the same quality.

In addition to consistently posting best in class drilling and production results, the Tulsa group continues to drive down costs through increased efficiencies and recent negotiation service contracts. As a result, we are seeing a 10% to 15% reduction in our 2013 average Woodford well costs. These savings are translating into a 24% increase in our projected rates of return, we are now forecasting return to north of 80% utilizing script pricing.

In addition to our drilling activity, we have been active in the leasing front in the Woodford. Since November, we’ve acquired an additional 7000 acres in liquids rich areas of Woodford. With these bolt-on acquisitions, we have significantly increased our liquids inventory and have many years of liquids rich drilling ahead of us benefitted by our joint venture.

Moving on to Gulf Coast, we have set all necessary intermediate casing and are currently drilling 16,120 feet with approximately 1800 feet to take TD on the Broussard Estates stage number three. If all continues as planned we expect to reach total depth in the lower (inaudible) a lobe in approximately two weeks. First production from the Broussard Estates stage number is expected in June and at that time our La Cantera gross production is projected to be an impressive 120 to 130 million cubic feet equivalent per day of which 30% is projected to be liquids.

Moving a couple of miles north of La Cantera territory, Thunder Bayou prospect where we recently received a data from a 3D survey, we’re very encouraged with our initial interpretation of the new data and believe there could be multiple projects on this leased position. We continue to lease in the area and therefore decided to not providing additional details regarding this project at this time other than we expect to spud Thunder Bayou in the second half of the year.

In addition to LA Cantera and Thunder Bayou, we have several high impact oil projects in South Louisiana. Our overlay prospect is currently drilling at 12,100 feet and is expected to reach total depth in two weeks. It has a gross unreached reserves of 1.3 million barrels equivalent and we have an approximate 22% working interest. Next up is Sawgrass prospect, we have a 2 million barrel equivalent target and we will spud during the second-quarter. We have an approximate 35% working interest in this well.

Finally, our Tokay (ph) prospect at Ship Shoal 72 Field where we have – we were four out of four last year, is slated to spud during the third quarter and exposes us to 2.5 million barrel equivalent target. We have a 50% working interest in this well.

Moving back to Mississippian Lime, as previously stated we remain encouraged by what we've seen from our producing wells and the trend where we achieved an average 24 hour rate of 425 Boe and a 30-day average rate of 255 Boe. Our 30-day average is right down the fairway when compared to SandRidge, the most active operated in the trend on a 30-day average rate based on a significantly larger statistical data set. Our 3D shoot is expected to commence in K in approximately one week, and the Pawnee county shoot is scheduled to begin in the second-quarter.

Again, we are encouraged that the 3D data from these shoots when modeled with our wellbore data will result in higher production rates and EURs. All of our current activity is taking place in Grant county where we have three wells in the following stages. PQML number 13 is currently being completed. PQML number 14 is scheduled to be completed in one week and PQML number 15 is expected to spud in two weeks. We expect to provide an update of these wells during our next operations update press release.

Finally, touching on East Texas where we recently reached total depth, on our latest 100% working interest Cotton Valley well. This 4300 foot horizontal well is expected to be completed in mid-April. We are very excited about these assets where we grew our liquids production 56% last year and our average well during that program was booked at 972 in Boe. However with the advantageous drilling promote structure available in the Woodford, those returns are superior to the Cotton Valley in this commodity priced environment. The assets are completely HBP and we are not at risk of losing any acreage.

With that, I will turn it over to Bond.

Bond Clement

Thank you, Charlie. During the fourth quarter we recorded a net loss of $25 million or $0.41 per diluted share. We generated discretionary cash flow of approximately $20 million. For the full year we recorded a net loss of $137 million or $2.20 per diluted share and generated discretionary cash flow of $77 million. Our fourth quarter and year end results included ceiling test impairments of $28 million and $137 million respectively.

During the quarter, our LOE totaled $10.5 million or $1.18 share per Mcfe which was slightly higher than the range of our guidance primarily due to a couple of un-budget workovers in the Woodford and East Texas. For the full year, however, LOE per Mcfe was $1.15 which was at the low end of our original full year guidance.

G&A costs for the fourth quarter totaled $5.4 million and included $1.3 million of non-cash stock comp expenses. Overhead costs were slightly lower than our guidance. Interest expense during the fourth quarter totaled $2.8 million which was also in line with our guidance. We capitalized $1.6 million of interest during the quarter, so in total our interest costs were $4.4 million.

Moving onto the balance sheet, during the quarter we invested about $20 million in CapEx. The breakout of this capital is approximately $15 million of direct CapEx, $0.5 million of acquisition costs and about $4.2 million of capitalized overhead and interest. For 2012, our CapEx spend came in line with guidance at $135 million. In December and January, we did close the sale of two non-core assets for net proceeds of approximately $20 million helping to close some of our cash flow to CapEx gap generated in 2012.

As Charlie mentioned, we have reduced our 2013 capital expenditure budget 35% as compared to 2012 in order to be more closely aligned with projected cash flow. This year’s budget calls for spending between $80 million and $100 million and we plan to operate approximately 95% of these projects. As always, this allows us to be flexible and we will adjust our spending either up or down depending upon how fluctuating commodity prices impact our cash flow.

In addition, we are currently evaluating the sale of our Eagle Ford assets and continue to pursue the sale of Niobrara assets. Proceeds from these proposed divestitures would be allocated back into our 2013 drilling program or utilize to pay down borrowings in our revolver.

Looking at production guidance for the year, our current plans call for producing between 90 and 95 million equivalent per day, the midpoint of which would be up about 5% to 6% from last year pro forma for the Fayetteville shale in December. Our production mix for the year is projected to be 80% gas, 12% NGLs and about 8% oil.

On the hedging front, we recently executed our first gas hedge for 2014 as well as an additional gas hedge for 2013. Our 2014 gas hedge was 10 million a day swap with the 404 floor and the additional 2013 gas hedge was for March through these with a 350 floor. We now have approximately 10.3 Bcf or roughly 40% of our projected gas production hedged for 2013 at an average floor price of about 350 per Mcf and we also have about 250 barrels of oil per day hedged based on LLS index of $104.75.

With that, I will turn it back to Charlie to wrap up.

Charles Goodson

Thank you. As we look out to the rest of 2013, in addition to our continued activity in the Woodford benefitted by our joint venture and internal rate of return continues to provide, we have several significant catalysts coming in our La Cantera number 3, Thunder Bayou, overlays, Sawgrass, and Tokay projects. While it’s still true that our production profile is primarily gas, it is important to realize that too much emphasis these days is placed on production mix. When one dives down a little deeper and looks at each one of our projects and the rate of return standpoint as opposed to a simpler production profile, there is significant value being created from our core assets. For example, our liquids rich Woodford program with its 75 for 50K (ph) is generating rates of return over 80% which is comparable to most pure oil plays.

With $71 million joint venture funds remaining at December 31, these attractive rates of return are essentially guaranteed for many more years. Our Gulf Coast projects offer the potential for the quick payouts, substantial cash flow and most importantly again impressive rates of return. While we like others which drove to produce more oil, this is not the only way to create shareholder value in this environment. We will continue to focus on driving down costs and look at every project from a rate of return standpoint because at the end of the day this is so important to the continued growth of a company.

With that, we will open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) And our first question comes from Ron Mills of Johnson Rice.

Ron Mills - Johnson Rice

Question on the Woodford, one of the I guess, commentary I have gotten on the Woodford is there’s not much running room but it sounds like you’ve added 7000 acres in the liquids rich portion of the play and in the discussion you put in your press release from earlier this month, it sounds like that adds kind of 70 to 100 potential drilling locations in the liquids rich area. Is that number right and of your 60,000 acres, what sales (ph) breakdown now in terms of liquids versus dry?

Charles Goodson

Ron, that is correct, that’s probably at between 70 and 100 and as of right now, we think we’re probably around call it 15, 12,000 to 15,000 of liquids rich acreage out of our 60,000, and as you can see from the last quarter we have added, we are continuing to add in that area because of the result that we have had. This recent past confirmed our enthusiasm with it, we have driven the costs down to around $4 million to drill these things right now. The Tulsa team is in full development mode in the Woodford operation and we just see the returns as highly acceptable for what we are looking at right now. Any increase in the gas price that come down the road is only going to enhance that part of this (ph). So I’d say somewhere between 12 to 15 right now and broadly.

Ron Mills - Johnson Rice

And the one rig you have there is that the plan as contemplated under the $80 million to $100 million budget or does the addition of the incremental locations and the results that you have in the drilling carry, make you think of that place as a potential place for more activities as we move through the year?

Charles Goodson

I’d say the first part, yes that is the current in the budget, that does have the one rig running and it has a pretty good chunk of acreage acquisitions and obviously when you are doing that, you are getting everything ready to ramp up the activity in that area. We obviously love this part of the trend, we love the economic especially with the promoted deal structure and so it’s an area that’s craving more activity and if a better gas price comes at us we generate more free cash flow too, we would definitely look to spend some more money in that area.

I think this laid it out, with the well costs where they are, with gas prices and with NGL prices where they are right now, we generate 80% of rate of return on a consistent basis. So we would envision most people would agree with that decision.

Ron Mills - Johnson Rice

And I couldn’t – I missed what Charlie said, how much is remaining on the drilling carry and based on your current plans, how far does that, that promo get you with next data (ph)?

Charles Goodson

A 71 million is left and as of right now we clearly see it going through 2014. Obviously if we pull rig activity into that area and accelerate it will (inaudible) carry quicker but that will be a decision that we want to pull that value forward and increase PV by growing out of the Bedford Bay which obviously would increase NAV as well.

Bond Clement

And Ron, if you think about it with a $4 million well cost, assuming that PetroQuest and NextEra have a 100% working interest, PetroQuest is paying about $1 million per well and we are utilizing about $1 million per well of Kerry, so that gives you some indication relative to the $70 million of how long it will last.

Operator

And our next question is from Tim Rezvan of Sterne Agee.

Tim Rezvan - Sterne Agee

Just a follow up quickly I guess on Ron’s question before, the well costs you’re talking about a $4 million range because I heard – I thought it was in the 5 million. Can you confirm that?

Charles Goodson

We’re currently drilling those around 4 to 4.2 is our current estimate and we are actually trying to lower below that. There is two different areas that we drill in, and so we’ve always provided somewhat of a blended well costs where the liquid rich area as you can imagine in the shallow area which is going to provide more liquids and this is going to have a lower cost because of a) shallower, b) the frac design has a lower volume and a lower pump pressure. So it’s the most advantageous area for us to drill for several reasons, the uplift that we get from the NGL pricing, and the lower well costs, obviously is going to increase rate of return.

Tim Rezvan - Sterne Agee

And just to make sure I heard you correctly, did you say with the carries, you’re at 80% IRRs?

Charles Goodson

Correct.

Tim Rezvan - Sterne Agee

When you look – I guess switching gears to the Eagle Ford what are your thoughts on how a timeline could work when you get the 3D results back in the second quarter? Assuming no surprises, could we see a rig ramp in 3Q or could we see some results possibly in the back end of the year, or do you think the missed line volumes are more of a 2014 story?

Charles Goodson

Right, just for a clarification, it’s the Miss Lime that we are doing the 3D work on the Eagle Ford, I just wanted to clear it up in the call. It’s really dependent on how soon we get the data which we are thinking is a third quarter event and assuming everything shoots out and we get some data knowledge, we could clearly be back to drilling later this year. I am not sure until we get the data it’s hard for me to say we could have a rig operating in the area and start posting results, but if we like what we see we will definitely be ready to get back drilling out there.

Tim Rezvan - Sterne Agee

And then if the Miss Lime side and the K’s expectation, is that – are the returns there going to be superior to the liquids rich Woodford or are you kind of agnostic between the two or --- to compete with each other?

Charles Goodson

If we have high curve type wells and we are able to drill wells that the industry has been referring to, I would assume that oil prices in there is going to run out because of the high oil work, we are 75%, 80% oil on our floor rates right now. Basically speaking so far the liquids rich is winning out because we are able to bring eight wells along and we just did it and post superior results to what we have been showing in the lime. But that’s where the hope of seismic we will be able to bring in that statistical variability and we will be able to produce a more consistent well results and if we do get to that point, then the economics will pay for that.

Bond Clement

And also Tim, the point that I made of, when you look at the same from 40,000 feet, there is 10 to 15 rigs constantly active right under our acreage and we are available – access virtually all that data. So we feel like we’ll probably get a benefit, value benefit if they are successful, by also doing the 3D, the same point in time, we will be integrating what they are doing into this. So we’re just trying to explain that what we are doing is a very positive thing just like what we have done in the Woodford and other areas and the cessation of six months or so is very realistic but there will be lot of things happening that we will be looking at during that period of time.

Tim Rezvan - Sterne Agee

I appreciate that color, and then one last one. You mentioned that you are evaluating the shale in the Eagle Ford, I know that, I think it’s been discussed, is it reason why you kind of formally mentioned that today, you feel like you are closer to potential deal than you might have been?

Charles Goodson

I wouldn’t say that. I think we are in the process of just – we haven’t run a formal process on that Tim, but it’s clearly an area that there is some activity and people are looking at aggressively. So I don’t – we’re not signalling anything by saying that.

Operator

And the next question is from Curtis Trimble of Global Hunter.

Curtis Trimble - Global Hunter Securities

I appreciate the commentary on the Woodford well costs, I was wondering if I might be able to get projection on the Mississippian as well and then for the South Louisiana offshore wells, if you can give me an AFE on those.

Bond Clement

Well, on the Mississippi Lime, I think our well costs are going to be little different for each area, I think somewhere in the 3.5 to 4, low 4s is probably a accurate guess right now. We’re clearly not in any type of development there at all, we are now number 15, been drilled on separate paths with really no cost benefit savings. So ultimately we do have a full development mode, we will clearly anticipate driving those costs down.

On the South Louisiana side, it really depends on the prospect, we’re drilling a well down to 20,000 feet, we’re going to be looking at just like La Cantera as well, the $20 million well costs, the third La Cantera well is obviously a side-track if you know, which is more in the $7 million to $8 million of lease costs get it down because we are utilizing the existing wellbore but a great field development it’s Thunder Bayou being in that $20 million range. And most everything else, that we are talking about today, be it overlays, sawgrass, tokay, those are all in the $5 million to $7 million range from a growth standpoint. As you know, Curtis, we sell out to a working interest that's manageable on most of these depending on the size of the well. So our net exposure is much lower than that, and we do try to provide that data, what are our estimated working interest and our estimate of paying it, because lot of times we will sell this down on a promoted basis, if possible. And so obviously our net capital will be lower.

Curtis Trimble - Global Hunter Securities

Sure, sure and that $5 million to $7 million on Overlay, Sawgrass, Tokay, that's the gross figure?

Bond Clement

Yes, that is.

Curtis Trimble - Global Hunter Securities

Just one other quick question. Can you kind of give me insight into your projections on balance sheet transitions as you move through 2013? Are you looking to keep debt at the $200 million current level? Or do you foresee some machinations in that?

Bond Clement

Well, our current plan calls to drill right around cash flows. So obviously we will have days where we are able to pay back a little bit on that revolver and days that we’re going to need to draw a little bit on the revolver just for working capital needs. But from a net, net exposure standpoint, I think the balance sheet is anticipated to be roughly flat with where we are year end from a debt perspective.

Curtis Trimble - Global Hunter Securities

One other just commentary on the Cotton Valley and held by production, et cetera. As you move through the sales process on the Eagle Ford and Niobrara, is it possible that the Cotton Valley could fall into that monetization effort as well is that –

Bond Clement

No, that’s not an asset that we are looking to sell. That’s a great long term asset that’s core for this company. And it’s just a victim of lower gas prices and better return because of other items i.e. promote or just growing success down in South Louisiana with liquids cut. We are extremely excited about what we have done out there, last year’s results as Charlie mentioned on the call ordering a million barrels equivalent EURs given to us by a third party reservoir engineer is a great asset, it’s just – it’s not time to throttle down that right now.

Operator

And our next question comes from Amir Arif of Stifel Nicolaus.

Amir Arif - Stifel Nicolaus

Just a couple of quick questions. On the -- in the Miss Lime, the 3D seismic, is that going to determine if you go back in or are you going back in anyways and that's sort of being used to help determine well placements?

Charles Goodson

Our anticipation is that it’s going to help us big locations, it’s going to show us areas, obviously we drilled some wells that were very, very successful, and so what we’re hoping is to isolate areas that we’re going to pick locations that give us the result like the 1000 barrel equivalent IP rate. So that’s the anticipation and we will have to wait to see what the data shows us.

Amir Arif - Stifel Nicolaus

And where is that seismic focused again, which of the three areas?

Charles Goodson

It’s two different shoes, the quicker of the two will be in Kay county and Pawnee will be the second one that comes out.

Amir Arif - Stifel Nicolaus

And then just a final question on the $71 million remaining in the JV, how much of that are you or will you be using up this year? About $30 million or is it a meaningfully different number than that?

Bond Clement

It’s probably going to be less than that, Amir. If you look like as Ron, if you look at the metrics on utilization per well of somewhere around $1 million, we’re going to drill 12 to 15 liquids rich wells. So you could probably think about 20 – around $20 million as a ballpark number for utilization this year. Obviously dependent upon if we increase our CapEx budget in the back half of the year, depending upon the results of seismic, and/or gas prices.

Operator

And next we have a question from Jason Lazarus of Intrepid Capital.

Jason Lazarus - Intrepid Capital

My question was pretty much answered. But I was just wondering if you had a sort of internal leverage target or ceiling that you wouldn't go above?

Charles Goodson

Jason, I think as we look at the various metrics that are out there, we are probably more focused on debt to EBITDA than any of the other balance sheet type metrics. So we obviously want to keep that number somewhere around 2 to under 2, is what our ideal threshold will be.

Operator

This concludes our question and answer session. I would like to turn the conference back over to management for any closing remarks.

Charles Goodson

I’d like to thank everybody for their time and continued support this morning. And we will hopefully see everybody at the IPAA conference in New York.

Operator

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.

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