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PDC Energy (NASDAQ:PDCE)

Q1 2014 Earnings Call

May 06, 2014 11:00 am ET

Executives

James M. Trimble - Chief Executive Officer, President and Director

Gysle R. Shellum - Chief Financial Officer

Barton R. Brookman - Chief Operating Officer and Executive Vice President

Analysts

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Brad Heffern - RBC Capital Markets, LLC, Research Division

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Operator

Greetings, and welcome to the PDC Energy 2014 First Quarter Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. On the call today is Mr. James Trimble, Chief Executive Officer and President of PDC Energy. Joining Mr. Trimble on the call is Mr. Barton Brookman, Executive Vice President and Chief Operating Officer; Mr. Gysle Shellum, Chief Financial Officer; and Mr. Lance Lauck, Senior Vice President, Corporate Development.

It is now my pleasure to introduce your host, Mr. James Trimble. Mr. Trimble, you may begin your conference.

James M. Trimble

Thank you, Kevin. Good morning, and thank you for joining us today to discuss PDC's first quarter 2014 results and operational update. As the operator said, presenting with me today here is Bart Brookman, COO; and Gysle Shellum, the CFO. Also present is Lance Lauck, our Senior Vice President of Corporate Development.

Before I begin, let me draw your attention to the Safe Harbor language at the beginning of our presentation, which will cover any forward-looking statements made today during our presentation.

I will present some highlights for the quarter, followed by Gysle on financials and then Bart on our operations, both of whom will go into greater detail.

We expect production growth of 28% to 35% in 2014 over last year, as we outlined the during Analyst Day presentations last month. Going into the first quarter of 2014, we had expected impacts to production volumes due to the natural decline of wells turned-in-line in the fourth quarter in both the Wattenberg and Marcellus, the sale of our shallow Devonian assets in December and historical weather impacts like freezing and severe winter weather. While we did see some very cold weather, our field operators did a great job minimizing any related downtime. Our production techniques in the Utica of holding back pressure on the wells minimized early declines. And the category that is hardest to forecast, Wattenberg non-operated production, volumes were higher than what we expected. With all this in mind, we saw production growth in the first quarter of 2014 by 44% over our first quarter of 2013. And over the same period, increased our liquid mix to 59% from 54%. And during that time, we grew liquid volumes by 57%. We had adjusted net income from operations of $9.1 million in the first quarter, but we reported a net loss of $2.1 million or $0.06 per share due to noncash expenses resulting from changes in fair value of unsettled derivatives of approximately $19 million pretax.

Product sales in the quarter were strong, as natural gas prices were higher due to cold weather across the country. Our balance sheet remains strong, and we have $585 million of liquidity as of March 31, 2014. Gysle will expand on our financial details shortly. Looking forward, we're adding a fifth drilling rig in the Wattenberg Field this month and expect to see a contribution to production from that rig by the fourth quarter. We expect to see Marcellus production increase early in the second quarter, as we turned-in-line 3 Armstrong-Reynolds wells in late March and got the fourth well into sales in early April, but expect a decline as we are not drilling any new wells in the Marcellus currently.

In the Utica, we turned-in-line the 2 Garvin offset wells in March, but production from the 3-well pad that include the original Garvin 1H has been limited by mechanical issues of a third-party midstream pipeline. We expect to bring the second rig in the Utica in the fall of this year.

At our Analyst Day, we announced the acquisition of 6,000 net Utica acreage in Washington County, and we showed new Utica type curves for our condensate and wet gas windows. I caution you when you're comparing our type curves to other operators in the Utica to compare the wells that are in close proximity and compare lateral lengths. In our type curves, we use 5,000-foot laterals, although we are drilling wells in the 6,000- and 7,000-foot lateral lengths.

To summarize, we had an excellent quarter both financially and operationally. We continue to focus on adding value for our shareholders and are in excellent position to execute our 2014 capital program and business plan, focusing on our liquid-rich horizontal plays.

I will now turn the call over to Gysle for his financial review of the first quarter. Gysle?

Gysle R. Shellum

Thanks, Jim, and good morning, everyone. As in the past, my comments are going to be high level, so I urge you for a more complete analysis to look at our press release and our 10-Q, which we filed earlier this morning.

As Jim mentioned, we're off to a good start for the year. Net production for the quarter was 2.4 million barrels equivalent, which was slightly above the high point of our guidance. In our budget, as Jim touched on, we anticipated more impact from weather than we actually saw, and non-operation -- non-operated production was about 50% higher than we forecast. All that was offset somewhat by Garvin wells in the Utica, which were constrained due to the third-party pipeline issue that Jim talked about. Bart will cover this in more detail shortly.

Sales for the first quarter were just under $130 million, a 63% increase over the first quarter of 2013 and an 8% increase over the fourth quarter last year. The increase was due to higher production and higher commodity prices. Our average per barrel of oil equivalent price of $54.05 in the first quarter of 2014 was 13% higher compared to the first quarter of 2013, driven by natural gas prices up 48% and NGL prices up 15%. These prices do not include settlements on derivatives, formerly called realized hedging losses and gains, which were negative about $8 million in the first quarter of '14 compared to a positive $8 million in the first quarter of '13.

Production cost on a per unit measure decreased about 7% quarter-over-quarter. Production cost include lifting cost, taxes, overhead and, beginning this year, a separate line item for fees associated with gathering, transportation and processing, specifically for Utica and Marcellus areas. In the first quarter of 2014, production cost averaged $8.83 per barrel of oil equivalent, $0.69 lower than the first quarter last year. In the fourth quarter of 2013, we averaged $9.28 per barrel of oil equivalent, so we were down $0.45 from the fourth quarter to the first quarter this year. Bart will talk more about lifting costs on a per unit basis, which were down 14% in the first quarter of '14 compared to the first quarter of '13. The comparative numbers for last year are all adjusted for the change in presentation for gathering, transportation and processing costs I just mentioned.

Gross margins were 84% of sales for the first quarter 2014 compared to 67% for the first quarter last year, which reflects the increase in average prices before realized hedge gains and losses. Increased liquids production as a percent of total production and lower production costs were also a factor that improved margin. Fourth quarter 2013 margins were slightly lower at 81% of sales.

Adjusted cash flow from operations is defined as cash flow from operations excluding changes in working capital. The upward trend here reflects the production volume growth that pushed oil and gas sales higher for the periods presented. Adjusted EBITDA in the quarter was up 25% compared to the first quarter 2013 and down 6% from the fourth quarter 2013, largely due to higher G&A that I'll discuss in just a minute. Adjusted EBITDA per diluted share reflects the issuance of shares in the third quarter of 2013, which was a weighted average increase of 5.4 million shares for the first quarter 2014 compared to the first quarter 2013.

DD&A includes depreciation on fixed assets and depletion of oil and gas properties. DD&A in the first quarter was up in total and at the high end of our range on a per barrel of oil equivalent basis due to the increased production and increased cost basis that is not offset by reserve adds in the first quarter. We expect the per unit DD&A would drop somewhat in subsequent quarters as new reserves get added. Depletion rates on oil and gas property only, which excludes depreciation on equipment, were $18.83 per barrel of oil equivalent in the first quarter 2014 compared to $16.06 per barrel of oil equivalent in the first quarter of 2013.

G&A costs were up in total and on a per BOE basis, mainly due to legal and related consulting fees in the current quarter. We are approaching the trial date on a long-standing lawsuit and costs begin to accumulate as you get close to that trial date. It originally was scheduled for May 21, but has been pushed to July 1. So about a little under $5 million of the increase in G&A was associated with consulting fees and legal fees related to those -- to that lawsuit.

The top half of the next slide reflects results attributable to shareholders for the quarter for GAAP, which includes unrealized gains and losses from mark-to-market hedge positions. All of the events I mentioned in my opening comments are included here. The bottom half of the page shows adjusted net income and earnings per share with unrealized hedge gains and losses removed, but includes the $28 million after-tax impact of the Piceance impairment in the first quarter of 2013. We left this cost in the table to be consistent with our prior presentations. Adjusting for this nonrecurring cost, we would have reported a net income of approximately $8 million or $0.25 per share in the quarter ended March 31, 2013.

In 2013, we extended the maturity of PDC's revolver to 2018 and have maintained a borrowing base at -- our borrowing base at $450 million, all of which is undrawn. We're going through our May redetermination currently, and our next redetermination is scheduled for November. We are not seeking an increase in the borrowing base in the current redetermination, but we'll evaluate the need to increase the borrowing base as the year progresses. We exited the quarter with $146 million of cash, which, along with cash flow from operations, is expected to fund most of our 2014 capital program. We expect to begin drawing on the revolver in the fourth quarter this year. The exact timing will depend on capital outlays for non-operated wells, the arrival of the fifth rig in Wattenberg and timing of the second rig in Utica.

The table on this page reflects PDC's consolidated borrowing. Our consolidated financial statements include our proportionate share of Marcellus joint venture debt, which has drawn $52 million to PDC's interest at year end. The joint venture debt is nonrecourse to PDC and doesn't count against our $450 million borrowing base. Liquidity, including cash on hand and available borrowing base at March 31, 2014, is approximately $585 million. And lastly, our $500 million high-yield debt issue matures in October 2022.

Our hedge positions for 2014, 2015 and 2016 are shown on the next page. We've hedged substantially all the oil and gas production that we're allowed to hedge under our terms of our credit agreement for 2014. For 2015, about 70% of our allowable production is hedged based on our year-end 2013 reserve report. We're working on adding to our 2015 and 2016 positions, and recently added some oil collars for 2016. Our philosophy hasn't changed on hedging. We believe the shape of the oil curve will continue to look similar, and prices in 2016 and beyond will move up over time. Our gas hedges are all in the $4 range, and we're settling at higher prices today. We don't, however, think current prices will hold long term, so we try to take advantage of the current runups when we can.

With that, I'll turn this over to Bart for a discussion on operations.

Barton R. Brookman

Thank you, Gysle, and hello, everyone. The first quarter of 2014, an excellent quarter for our operating teams. As Gysle noted, production came in at 2.4 million barrels of oil equivalent, right in line with the high end of our guidance. This is 26,690 barrels of oil equivalent per day. As Jim noted, a 44% improvement from the same period 2013. Very pleased with the production distribution across our operating basins. 77% of our production is now coming from the Wattenberg Field, 15% from our Marcellus in Northern West Virginia and now, 8% of the company's production is coming from the Utica. In Wattenberg, we saw first quarter production of 20,544 BOE per day, a 34% growth level from prior year levels. In the Utica, 1,000%-plus production growth, since we are just beginning to establish a firm production pattern in that basin. And overall, in the Utica, 2,194 barrels of oil equivalent per day. And then in the Marcellus, in the first quarter, we had 23,721 (sic) [23,712] Mcf equivalent per day. Again, this is our dry gas play. This equates to 3,952 BOE per day, a 35% improvement over prior year levels.

Let me give some production highlights. As the lower left bar graph shows, first quarter 2014 net volumes came in 4% above the midpoint of our guidance. The company's overall liquid mix was 59%. In Wattenberg, as Jim noted, we expect the fifth rig to arrive in a week to 10 days, and will begin drilling in the inner core area, our highest reserve performance area in the field, and should begin contributing to production sometime in the fourth quarter. The Waste Management 16-well downspacing project continues to perform above our expectation. This project supports ongoing development in the field at 16 or more wells per equivalent section. I should note, we had severe weather conditions in the first quarter, particularly in Ohio and Colorado, which did negatively impact our production. And the repairs from last fall's flood in Colorado, I'm happy to announce, are nearly 100% complete. In the Utica, we established first sales from the Garvin 3-well pad. We continue to be limited by Blue Racer as they work through a series of repairs on the main sales line in that area. But overall, the Garvin pad right now, 9 million cubic foot per day, 300 barrels of condensate. I should note, all 3 wells are currently held back on approximately 16/64 choke. On the Palmer pad, 2 wells are drilled. We are now on our third well. And I anticipate first sales from this pad late this summer. In the Marcellus, 3 of the 4 Armstrong-Reynolds wells were online as of late first quarter 2014. And the fourth well on this pad came on in early April. All of the Armstrong-Reynolds wells right now are performing above our type curve expectations, as we have done some reengineering of our Marcellus completions. I should clarify that the first quarter had no shallow Devonian production due to the sale of these assets last December.

Let me walk through the production trends from fourth quarter 2013 to first quarter 2014. As you can see from the bar chart, fourth quarter production was 26,131 BOE per day. We added 498 BOE per day in the Wattenberg due to the ongoing development and drilling programs and lower line pressures. In the Utica, we added 505 BOE per day, again, ongoing development and early contribution from the Garvin pad. And then in West Virginia, our 50% of the JV, we had a net decrease of 444 BOE per day. This was primarily due to the sale of our shallow Devonian assets, which takes us to 26,690 BOE per day average first quarter 2014.

Let me give an update on the Utica. Not a lot of new information here technically, given we've just had Analyst Day a couple of weeks ago, but again, we're very pleased, as Jim noted, increasing our acreage position by 6,000 net acres to 54,000 acres in this play. With our 700- to 800-foot spacing, our current practice on drilling between laterals, we now have approximately 300 horizontal locations in inventory. Approximately 20% of our acreage position is in Guernsey and Northern Noble counties and 80% is now Northern Washington and Eastern Morgan County area. The Garvin pad, as I noted earlier, continues to produce at very promising levels both production and pressure under pipeline constraints, again, 9 million a day and 300 barrels of condensate gross from the 3 wells, all are on approximately 16/64 choke. Based on the very early production and pressure data, our reserve group anticipates all 3 of these wells will be in line or exceed our wet gas type curve. On the Palmer pad, as I noted, we expect production from this pad late this summer. And the second drilling rig should be deployed in the Utica sometime in the fourth quarter, most likely October-November timeframe.

Let me cover the drilling activity for the company in total for the quarter. As I noted at Analyst Day, we will be reporting turned-in-lines, and we'll call this TILs, as our primarily measurement of drilling activity, but we'll also be reporting spuds for each quarter. From the bar graph, you can see we turned-in-line 18 wells for the quarter with a plan of 17, so right in line with our overall guidance.

Broken out by area. Wattenberg, we had 13 horizontal turned-in-lines and we spud 24 wells. In the Utica, we had 2 turned-in-lines, the Garvin wells; and we spud 3, which are the Palmer wells. And then in the Marcellus, the Armstrong-Reynolds wells, which were drilled in 2013 and completed in the first quarter of 2014, 3 of the 4 came online in March and again, the fourth in early April. From a non-operated perspective, as Gysle noted, this is a growing part of our business. We had 11 wells turned-in-line, all of those in the Wattenberg Field, and average working interest of 20% for these wells, and we spud 13 non-operated wells. So our total operated/non-operated activity, we turned-in-line 30 wells for the quarter, and we spud 40. We are right on plan right now overall drilling activity for the year, which is gross operated and non-operated spuds of 199 wells and 166 wells turned-in-line. Again, our current drilling activity: 1 rig in the Utica, 4 rigs in the Wattenberg, and within the next 10 days, we should have our fifth rig running in the Wattenberg, in the inner core area.

Let me update everyone on CapEx, capital budget for the first quarter. The company spent $125 million, $86 million of that was in the Wattenberg Field for ongoing horizontal development. Let me break out that $86 million: $70 million of it is operated and $16 million of it is non-operated. $28 million was spent in the Utica, both leasing and developmental drilling. $11 million in our JV partnership in the Marcellus. That is our 50% share for the completions of the Armstrong-Reynolds pad. For the year, we are on target for a $647 million capital budget, assuming the non-operated projects that are accelerating fill the $50 million gap, which was moved from 2014 to first quarter 2015, for our 41% share of the 26-well non-operated Niobrara project.

Talk about lease operating expenses. Let me explain a little more detail on the new accounting methodology that Gysle talked about. This does not impact our operating margins or our operating cash flow. But effective January 1, '14, a portion of the gathering and processing will not be included in lifting cost. These gathering and processing expenses are reported as a separate line item in our financials. This change was made to provide better clarity of the company's true lifting cost. From the bar graph, you can see amended guidance of approximately $3.80 annualized lifting cost. First quarter actuals of $3.41 per BOE, approximately $0.50 per BOE under our expectations. Bottom line, we are very pleased with the overall cost structure of our operations in the first quarter.

So some operational highlights. In the Wattenberg again, first quarter production, just over 20,000 BOE per day. 13% of this basin's production is now non-operated. Happy to announce that over 50%, 52% of the company's operated production is now from our horizontal programs. We spud 16 horizontal Niobraras, 8 horizontal Codells. Our drilling and completion costs remain at the $4.2 million level. That is for our 4,500-foot lateral with approximately 16 stages. The Waste Management pad continues to provide very encouraging data. The drilling on the inner core will begin this month, and we have 20 long-lateral projects planned this year in this basin.

In the Utica. We're very happy with our 54,000 net acre increase. We have continued strong, stabilized production from this project. Most of our acreage is in the liquid-rich window, providing tremendous economics and opportunity for the company. We currently have 13 wells producing, and our current cost structure is $9 million for a 5,000-foot lateral with approximately 20 frac stages.

And then in the Marcellus. Current cost structure of $6.5 million per well. We divested the 3,500 shallow Devonian wells in December, really helping improve the overall company cost structure. And we have the Armstrong-Reynolds 4-well pad right now performing at or above the type curves.

With this, I'm going to turn it back to the operator for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Welles Fitzpatrick with Johnson Rice.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

After the success of the Waste Management and all the microseismic and all that good stuff you guys went through on the Analyst Day, I believe there is some talk about moving around some of the wells on the Sunmarke and the Chestnut pads? Are you still looking at doing 2, 2 and 4; and 2, 3 and 5, if I remember the configurations on those?

Barton R. Brookman

The answer is yes. We are looking at moving -- and we don't have the ability to move laterally in the plan, but the state does let us take a proposed Codell well and move it to the Niobrara. And our operating teams right now, based on Niobrara data and Codell data in the more inner core portion of the field, I think they are strongly considering moving 1 or 2 of the laterals up to the Niobrara.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Okay. And so then that would be -- I just want to make sure my math's right. What spacing would that then be testing in the B?

Barton R. Brookman

Oh, boy, Welles, I'd have to look at the final schematic to give you that number.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

No, no, fair enough. And then one on the same topic in the Utica. It seems like you guys have kind of settled into 700- to 800-foot spacing. Any plans to test tighter than the 700 test you guys have now?

Barton R. Brookman

I don't think so because early on our Detweiler pad, where we were testing some tighter spacing, we think we found the limit. So I think that 700 is probably the short -- or the tightest we would go right now in that play.

Operator

Our next question comes from Brad Heffern with RBC Capital Markets.

Brad Heffern - RBC Capital Markets, LLC, Research Division

Just a quick question on the non-operated production. As you guys said, it was 50% higher than you were expecting this quarter. How do you guys think about how that's going to trend going forward, and is this sort of onetime blip or does it revise upwards your thoughts for non-op for the rest of the year?

Barton R. Brookman

I would say, it absolutely revised our thoughts up for the year. The trend for non-operated is increasing. As everyone knows, we had $100 million budgeted in Wattenberg. That included the 26-well non-operated project, which was $50 million of the $100 million. And right now, our operating teams are anticipating our non-operated without that $50 million for the 26, which has been delayed until '15, will be somewhere around $75 million to $100 million. So the pace of these projects is growing, which is adding to the production base as we go through the year.

James M. Trimble

Brad, I would just say this, sort of what we gave at the Analyst Day. We said we were tending on the production side to be on the high side of our guidance.

Brad Heffern - RBC Capital Markets, LLC, Research Division

Right. Okay, got you. So excluding the non-op volume, would you say the operated performance is consistent with what you had originally planned?

Barton R. Brookman

I would say that's a fair statement, yes.

Brad Heffern - RBC Capital Markets, LLC, Research Division

Okay, great. And then just looking at the cost side, I think that there's -- whether you include or exclude the transportation component that's broken out now, there's a pretty nice decrease in the first quarter. I was wondering how much of that has to do with losing some of the conventional wells that were in there that were probably high LOE, and how much of it is just better expense control?

Barton R. Brookman

Well, we did the best we could to budget the Devonian not being part of our operation. So the guidance that we provide does not have those costs in there. But what we're seeing in our cost structure right now are really 2 things: the production is performing slightly better, including the non-op we just talked about, which helps dilute the per BOE slightly; but also, our Utica lifting costs right now are tremendous. The team's doing an outstanding job. And from what we budgeted and anticipated, the Utica right now is coming in substantially under on an operating cost basis. I would caution everyone, we have got water disposal costs. We've got long-term artificial lift plungers. A lot of things that we'll be executing on in the Utica, so that cost structure will probably start creeping up on us. But right now, we're very pleased with what the Utica team is doing. The Wattenberg cost structure right now is right in line with our expectations. I think the team has done an outstanding job there with all the high line pressure from last year, lower line pressure is rolling into this year. We still have some compression cost, but the biggie from the Wattenberg right now is the ongoing increases in regulatory, air monitoring and different things that we have hitting the field. So our cost structure there, I think we're doing a really good job of predicting.

Operator

Our next question comes from Mike Scialla with Stifel.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

I want to ask you about your guidance for production, pretty flat for second, third quarters with the first quarter, and you got quite a few wells coming on second, third quarter relative to the first quarter. Is that some, I guess, maybe caution on midstream issues potentially or is it just overcoming the decline of the Marcellus, or can you discuss that at all?

Barton R. Brookman

Yes. And let me see if I can map this because we anticipated this question based on, I think, 33 turned-in-lines. First, a good portion of those turned-in-lines are in June per our budget, so that's the first thing that -- for the second quarter. A large batch of those are going to be later in the quarter. Second, as we go through the second and third quarter, we really don't have any Utica adds. I mean, the Palmer pad is our next real online, and I think it's going to come on fairly -- probably late summer right now. We do have increased curtailment factors in the summertime in the Wattenberg Field, so we anticipate, even though we're seeing excess capacity right now in DCP, summertime operations we always have additional line pressures and downtime due to temperatures. We had a large number of turn-ons, particularly in the fourth quarter and also in the first quarter, so we're always offsetting those declines. And then to your point, we have a very steep Marcellus decline right now from the O.E.S pad and the Armstrong-Reynolds pad that are on a very aggressive decline. So the Utica and the Wattenberg have to offset that. And then last, we don't have the Devonian in there. So for the year, we continue to have to fill that bucket. So those are the big forces, Mike, and that's the high-level look at it. Obviously, when you add all that up, it results in that second and third quarter modest increases and then a steep increase in fourth quarter production.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

I appreciate that. That helps. Could you quantify at all the Marcellus decline on an annual basis or a quarterly basis? Do you have that number?

Barton R. Brookman

I don't have that with me, no.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay, no problem. I want to switch over to Gysle. You mentioned the lawsuit, the long-standing lawsuit. Could you elaborate on that at all? It sounds like that's hopefully coming to a close here. Also, I want to know, if you have it, how much of the G&A was noncash?

Gysle R. Shellum

Yes, let me see if I can address some of that. Obviously, I can't comment on the details of the ongoing litigation, but we have disclosed in the Q that -- the dates that I've mentioned when I was speaking earlier. The -- I don't think I can quantify the noncash piece of it. The total was just, as I mentioned, just under $4 million. And that includes legal fees, consulting fees and contingencies and a lot of other stuff. And that's about as far as I can go with it.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay. Last one from me. You showed at the Analyst Day, you've kind of redefined, with the industry data that you've been collecting, where the windows are for the Utica play dry gas window shifting a little bit further to the west, and same with the condensate and wet gas. I guess given that, any thoughts on -- as you look out, drilling -- what do you think about the dry gas play? It looks like some of your acreage now maybe prospective for that?

Barton R. Brookman

We haven't counted that out. It's not part of our '14 drilling. Our '14 drilling, Mike, is really focused on, I would say, we're targeting 50% liquids or greater. I think that will be the primary focus of our early '15 program, also into mid-'15 with both rigs. But we're learning a lot about the reserves in some of these IPs in the dry gas, so it's particularly in the southern part of the play. So as we go later into '15, you may see us propose. And a lot of that depends on our outlook for gas prices. We also have to give a lot of consideration in this area for the deduct of the differential. Because right now we're anticipating it's going to be somewhere between $0.50 and $1 as we go through the full year, yes, for the full year.

Operator

Our next question comes from Jeffrey Campbell with Tuohy Brothers.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

I want to return to the western extension of the condensate window that you announced at the Analyst Day. And I just kind of had 2 questions surrounding that. The first one was, I guess, the more obvious one, which is, when do you begin to think about drilling further west and sort of testing the theory as it were?

Barton R. Brookman

I would say that would be a late '15 initiative. We want to get the Palmer well completed and online. And I would say, we would -- our reserve team would probably want 6 months production data on that pad before we propose moving to the west of that. So that would put us, data-wise, early '15. And at that point, proposing a project which would probably be late '15.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. And thinking about it another way, what do you guys believe right now with regard to the industry as a whole? I mean, do think that they agree with your border revisions to the Utica or not? And if perhaps if they don't, does this present the opportunity to acquire some additional acreage?

Barton R. Brookman

The first part of the question, I can't comment on what they believe about what we say. I think we have credibility in the market, so I think we get some feedback that people really respect and look at our Analyst Day presentations and use some of that data. The second part, yes, there are acreage opportunities there. We continue to pursue acreage. We were happy with the 6,000-acre add. And our land team has multiple different acreage deals that we continue to hunt, some of those being in the Morgan County area.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. Shifting to the Wattenberg, I've been listening to some of the other operators in their calls, and they seem to be still very bullish and indicating that they don't believe that the potential to reduce drilling and completion costs have been exhausted. I just wondered if you could comment on what further cost improvements you feel you have line of sight on for the Wattenberg?

Barton R. Brookman

Okay. Yes, we are seeing cost improvements primarily due to drill times and increased pad size. And those are -- I would classify as significant forces up to a couple of hundred, $300,000-per-well type ranges. We've seen some of that come through in our numbers. But the offset to that is we are seeing some strong data supporting more stages per 1,000-foot of lateral, so tighter stage spacing, more like 200-foot per sleeve. We also have longer laterals that we're pursuing. We also have increasing cost structure, I call it demand pull, due to this boom cycle we're in, in the Wattenberg Field. So we've got offsetting forces right now. So that's why we stick with our $4.2 million cost structure on the Wattenberg.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. But it is fair to say if you're spending more on tighter spacing of fracs, you are also going to capture more EURs as a result?

Barton R. Brookman

That is correct. I think one thing we need to communicate to the market as we go forward is our drilling F&D, because I think that ties back to your question. If you're increasing cost but increasing reserves, are you guys driving your drilling F&D down. So I think that's a presentation over the next several months that would be good to show the trends for the company from that perspective.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay, my last question then, and if you don't feel it's fair or whatever, then don't worry about it. But you tried to communicate the Garvin, the fact that even the Garvins are impacted, yet on an EUR basis you believe -- type curve basis that they're going to do fine. Is there any way to just take a shot at it based on a daily production basis and just imagine what the wells might have looked like had they not been restricted by the pipeline issues?

Barton R. Brookman

We've done that on the Garvin 1. We presented that, I believe, 6 months ago.

Gysle R. Shellum

At Analyst Day.

Barton R. Brookman

At Analyst Day. So the answer is, yes. We have the ability to do that. But the real answer is always in the true production performance from the wells. Both the 2 and 3, we've got very, very early data. We're still cleaning up a lot of the flowback water. Because we're so choked back, we haven't been necessarily managing the flowback under our normal operations. So to answer your question, we're very encouraged by the pressure and the production rates. We would love Blue Racer -- and right now, the plan with Blue Racer over the next couple of months is they are slowly working the MAOP of this lineup. So over the next several months, they're going to be giving PDC extra room to increase our choke sizes on this line. They're doing that and monitoring pressure and performance on the line, so they can reclassify the MAOP on the line. So expect more data on the Garvin pad as we go forward here. It's just taking us a lot longer to really get the desired rates we'd like.

Operator

[Operator Instructions] Our next question comes from Jeffrey Connolly with Mizuho Securities.

Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

Just a follow up on Bart's earlier comments about frac stage spacing in the Wattenberg. At Analyst Day, you guys highlighted the one well on Waste Management and mentioned that you're going to test tighter frac stage spacing on some more wells. Can you share anything on that with us?

Barton R. Brookman

Well -- and I think we covered it at Analyst Day. We've got approximately 10 of these that we've executed on to date. And we've got another, I believe, 10 that our operating team is planning on. We've got mixed data on this right now. And we've got several wells. One, we presented very strong performance, and I think we've got some that we're really evaluating still. I think the thing to expect from both the tighter spacing and longer laterals, the early data may not be as encouraging, but it's going to be the longer-term data. You're breaking a lot more rock, so we're going to expect some flatter declines. So my message, Jeffrey, as we go through the year is, we're going to execute on 20 of these total. And by third and fourth quarter, I think we're going to have enough data to really see if we're moving the shape of the curve, which is going to enhance reserves. Obviously, the extra reserves for the discussion we just had on the prior question, is that enough to offset the increased cost.

Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

Great. And then just one housekeeping, should we expect any increase in G&A from the ongoing lawsuit to spill over into 2Q or was it all kind of recorded in the first quarter?

Gysle R. Shellum

This is Gysle. As I mentioned, the trial date is July 1, so there is ongoing legal work up to that trial date and probably beyond, if we actually get to a trial. So you can expect to see some in the second quarter as well.

Operator

Our next question comes from David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Washington County, some of that stuff is a little bit further south. Have you -- what are the plans for that acreage? Are you -- is that on the docket to drill at some point or can you give us some more color there?

Barton R. Brookman

It's not on the docket this year. It will be part of the '15 plan. And geologically, we've got a lot of confidence in everything you see on the map. Obviously, the eastern side of that is going to be a little bit gassier.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Yes. And then I know this is a little bit -- not directly offset to you guys, but a lot of people have gone to the dry gas window, right, pushing east in the Utica, if you will. Can you talk about your desire to get the acreage out there? I know it's probably not -- from a cost standpoint, probably not cheap right now, but can you just talk about any desire there?

Barton R. Brookman

We've looked at some projects, and they just haven't fit our business model, David. I think strategically, from our perspective, if we can be in that 30% liquids or west of that line, we prefer to pursue the acreage in that region versus the deeper gas right now. Remember, we've got 7 to 8 [ph] Bcf wells in our Marcellus right now at under $1 F&D. So we feel like strategically long-term for the company, if dry gas is our focus, we've got a pretty good project in Northern West Virginia.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, one more in the Utica. I know you touched on this a little bit at Analyst Day, but the retrograde condensate issues that some operators have talked about a little bit, can you -- any updated thoughts there of kind of what you're thinking about that in the play?

Barton R. Brookman

I don't know if I have any updated thoughts. I think operationally, we continue to hold with our position that pressure management is key. I think we presented that data at Analyst Day. Our operator -- our operating team here, I think, has a really good handle on this, and our reserve group has got a good line of sight. Our goal is to maintain frac connectivity for the life of the well through pressure management. So -- and I think we've got pretty good clarity of where the condensate, the wet gas window, the dry gas and the oil window is evolving to. So it gives us the ability to manage these wells as we drill them.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And one more for me on the Niobrara. You know I love to talk about my Niobrara infrastructure. Can you just give us a snapshot of -- I know right now we're kind of in a shoulder season, but as far as line pressures today versus a year ago, before the start-up of DCP, can you just give us -- can you quantify that in any way for us and just give us an update there?

Barton R. Brookman

Well, first, if I compare today versus a year ago, we are 50 to 70 PSI improved on average across the field. The O'Connor plant has provided relief to our operations. I should note, we have parts of the field, particularly in the northeast, that we still have localized bottlenecks. So that is still impacting our operating team who are working very closely with DCP on longer-term solutions for the northeastern part of the field. And the Lucerne plant, which is scheduled to come on sometime in the first half of 2015, will provide dramatic relief for the northern part of the Wattenberg Field. As far as current capacity, the first part of your question, right now, we're seeing anywhere, when everything is up and running, DCP's throughputs have been approximately 525 million to 550 million a day overall. And with the final stages of the O'Connor expansion, their total nameplate capacity of their field is right around 600 million a day. So they've got excess capacity. That will get impacted in the summer with temperatures. So will that come down and cause slight elevations to field pressures? Most likely, yes. But very important for the market to know, we don't anticipate it being anywhere near where it was a year ago. So we feel like we have good line of sight. We feel like we've modeled this into our production properly. And most importantly for everyone to know, we've got really good communications with DCP on expansions, well connects, long-term plans of drilling, volume forecast, all of that.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And just as a reference point part, the 50 to 70 PSI is up. Can you give us the -- what the references for that, like kind of what you saw at the peak?

Barton R. Brookman

Okay. 225 pounds at the peak average, with parts of the field over 300. And currently, our average is closer to 150 pounds.

Operator

Our next question comes from Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

This is a question on the Wattenberg Field, understandably that you guys are already the third-largest leaseholder in the basin. Just wanted to see your reaction to what EOG has announced today. I think they kind of have pushed the Codell play up to Laramie County in Wyoming, and these are extended laterals. So they look fairly good. Is this something that you guys care to pursue? And if not, do you think it can actually work fairly well, and is there a northern limit of sorts in Wyoming?

James M. Trimble

I have to say, sitting here, we haven't seen that this morning. So I don't think, Irene, we really can comment on it at this time. We haven't -- I'm sure our geologists themselves are looking all over, but we don't have any comments at this time.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Yes, but your current footprint, you don't really have anything left in the northern part of Wyoming. I mean, southern part of Wyoming or really the northern edge of Weld County either right?

James M. Trimble

We're really inside what we identified as the Core Wattenberg, is where all of our acreage is concentrated.

Operator

And I'm not showing any further questions. At this time, I'd like to turn the conference back over to our host for closing remarks.

James M. Trimble

Thank you very much, Kevin. And I'd like to just say, reiterate once again, thanks, everybody, for joining us for PDC's first quarter, which we thought was outstanding results. Appreciate it.

Operator

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.

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Source: PDC Energy's (PDCE) CEO James Trimble on Q1 2014 Results - Earnings Call Transcript
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