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PDC Energy (NASDAQ:PDCE)

Q2 2014 Earnings Call

August 08, 2014 11:00 am ET

Executives

James M. Trimble - Chief Executive Officer and President

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

Gysle R. Shellum - Chief Financial Officer

Lance A. Lauck - Senior Vice President of Corporate Development

Analysts

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

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

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Ipsit Mohanty - GMP Securities L.P., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Michael A. Hall - Heikkinen Energy Advisors, LLC

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

Jason Smith - BofA Merrill Lynch, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

David Snow

Operator

Greetings, and welcome to the PDC Energy 2014 Second Quarter Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.

On the call today is Mr. James Trimble, Chief Executive Officer of PDC Energy. Joining Mr. Trimble on the call is Mr. Barton Brookman, 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 now begin.

James M. Trimble

Thank you, and good morning, everyone, and thank you for joining us today to discuss PDC's second quarter 2014 results and operational update. As the operator said, today with me is Bart Brookman, who's President and COO; Gysle Shellum, CFO; and 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.

PDC had a great second quarter and a strong first half of 2014 with production and revenue growth and continuous success in our drilling in both the Wattenberg and Utica plays, which has led to our increase in our guidance for 2014 that you will hear about today.

In June, I was very pleased to announce promotion of Bart Brookman to President and COO, and my plan to retire at year end. I will remain on the Board at which time Bart has plans to succeed me as the CEO, beginning in January 2015. The earlier announcement allows for a very smooth transition within the company and a clear signal to our various stakeholders.

Last week, we announced the acquisition of an additional 13,000 net acres within our focus area in the southern part of the Utica play, which brings our acreage position to some 67,000 acres with over 350 identified drilling locations.

In addition, we also announced that we signed a purchase and sales agreement to divest our dry gas Marcellus assets that are held in a 50-50 joint venture. The sale is our final step in transitioning the company toward a high-quality, liquids-rich asset base.

Gysle will give you an update on our full 2014 guidance based on our strong results in the first half, and the impact on the sale of the Marcellus production, which we expect to close in the fourth quarter.

Last, we'll provide an update to the 3-year outlook, slides presented at our Analyst Day that now incorporates the new guidance.

As most of you know by now, on Tuesday of this week, the Colorado ballot initiatives were officially withdrawn. We look forward to an open, fair and fact-based discussions with the task force and realistic measures to address concerns. In the meantime, we will continue our outreach to stakeholders in Colorado with the focus on the Weld County communities where we operate. We will continue to focus our efforts on adding value for our shareholders as we even more focus on our liquid-rich horizontal plays.

I will now turn the call over to Bart for the quarter highlights and an operational update. Bart will be followed by Gysle, who will cover the financials and then Lance for the 3-year outlook.

Barton R. Brookman

Thank you, Jim, and hello, everybody. As Jim mentioned, we had a tremendous quarter with an increase in production of 64% when compared to the same quarter last year. This is primarily due to the outstanding efforts of our Wattenberg team. But I also want to acknowledge all of our operations and EH&S teams for their efforts during the quarter as we increased production significantly in a safe and efficient manner. Sales for the quarter were up 81% to $140 million, primarily driven by the increased production volumes. Cash flow for the company from operations was $55 million; however, after excluding the impact of the litigation charge that Gysle will discuss shortly, adjusted cash flow from operations would have been $76 million.

Our Wattenberg Field continues to be a big driver in our growth. In this basin, production was up 55% over the second quarter of 2013. Non-operated production for the company, primarily from the Wattenberg Field, was 2x our budgeted levels at approximately 3,600 BOE per day.

With the sale of our Marcellus assets, announced 2 weeks ago, we will strengthen our balance sheet and use these proceeds to accelerate the growth of the company in the remaining 2 liquid-rich basins. We're also very pleased to allocate part of the expected proceeds to expand our leasehold in the Utica, particularly in Northern Washington and Eastern Morgan County areas with 13,000 net acres that we recently acquired. Our total Utica acreage now stands 67,000 net acres in this play.

Going forward, we remain focused on 2 horizontal -- focused on horizontal drilling in our 2 asset areas. The Wattenberg, where we recently added the fifth rig and the Utica, where we recently added our second drilling rig. As of June 30, we had $478 million of liquidity and with the proceeds from our announced sale of the Marcellus assets, our balance sheet will be even stronger upon closing of this transaction.

Let me give a detailed operational update. Again, second quarter 2014, an excellent quarter for our operating teams. Production came in at 2.7 million BOE for the quarter, 15% above the midpoint of our guidance. This is 29,700 barrels of oil equivalent per day, a 64% improvement from second quarter 2013, and an 11% increase from the first quarter of 2014.

Wattenberg accounted for 77% of the company's production. Wattenberg also saw a quarterly production level of 23,300 BOE per day, a growth of 55% from the same quarter last year.

In the Utica, we experienced excellent production growth quarter-to-quarter, since a year ago we were just beginning to establish production for this basin. Overall, production in the Utica was 2,100 barrels of oil equivalent per day and I should note that all 3 Garvin wells were shut in for a very good portion of the second quarter.

And then in the Marcellus play, in the second quarter we had 25,800 Mcf equivalent per day, again, this is our dry gas play, this does equate to 4,300 BOE per day. This is a 52% improvement over prior year levels.

Let me give some production highlights for the quarter. As shown in the lower left bar graph, second quarter 2014 experienced nice growth from the first quarter. The company's overall liquid mix was 55%. In the Wattenberg, the fifth rig was deployed in June into the inner core region of the basin and this is expected to begin contributing to production sometime in the fourth quarter. The non-operated production from the Wattenberg Field continues to increase at an aggressive pace and we continue to see strong flow of non-operated projects in this basin.

In the Utica, the second rig was deployed in early July and will begin contributing to production early next year. The Garvin 3-well pad after a series of midstream challenges, not related to PDC's operations, is back online. Currently, we have no midstream restrictions and I will provide an update on the performance of this pad in a moment.

In the Utica southern acreage, we expect first sales on our Palmer pad in Eastern Morgan County sometime in early September. And then in the Marcellus, again, we were pleased 2 weeks ago to announce the sale of our 50% interest in the Mountaineer joint venture, sales price of $250 million that is net to PDC and the transaction is expected to close about mid-October.

New production guidance. Let me walk-through the updated guidance for the company. There are a lot of moving parts here, so please bear with me. I will begin on the far left of the graph, which is the original guidance of 9.5 million to 10 million barrels equivalent. First half actual performance is 600,000 barrels above our guidance, so it's an uptick of 600,000 barrels. Next, in the second half of 2014, we are anticipating 300,000 barrels improvement from the original guidance based on our drilling programs. Then the third green uptick, our non-operated production is another 200,000 barrels uptick in the second half of 2014.

For an updated guidance, including a full year of the Mountaineer Division to 10.7 million to 10.9 million barrels equivalent. Recognizing we are selling the Mountaineer Division, our dry Marcellus gas assets, most likely closing in mid-October, we have a reduction in October, November and December volumes of approximately 300,000 barrels of oil equivalent to get us to our revised guidance 2014 of 10.4 million to 10.6 million barrels equivalent. Gysle will provide full financial outline for these new production guidance volumes in a moment.

Let me give some of the highlights for the Wattenberg Field. First on the map, you can see the location of the 5 rigs currently running in the basin, 2 in the outer core, 2 in the middle core and we deployed the fifth rig to the western portion of the inner core. Drilling on all 5 of the rigs is on schedule and we are on pace for 115 to 120 spuds anticipated this year. All of our development is averaging at or above our type curve, so outstanding production performance from this drilling program.

For the year, we have a slight shift in the number of Codells and Niobraras. The mix will now be approximately 55% Niobraras and 45% Codells. As we move toward the inner core, we are finding the Niobraras to be outstanding production performers and therefore, we have moved a few of the Codells nose areas to the Niobrara.

Current drilling and completion costs remain $4.2 million. As I noted on earlier calls, we have approximately 20 longer lateral projects planned for the year and 25 tests of increased stage density completions. Our completion team continues with ongoing technical improvements and testing of different methods in 2014, including several plug-and-perf jobs. In year-to-date, our non-operated production for this basin now accounts for 15% of the Wattenberg total. We also continue to be on pace for our 3 down space projects beyond the 16-well equivalent per section we had on the Waste Management project.

Our Utica project in Eastern Ohio. As noted earlier, we couldn't be more pleased to have increased our acreage position by 13,000 net acres to over 67,000 acres in this play. 21,000 of these acres are in the condensate window, 45,000 of these acres are in the wet gas window and our current inventory of drilling projects is estimated at 350 locations. Again, on the Garvin pad, the midstream constraints we experienced for a good portion of the second quarter have been corrected and that 3-well pad is up and producing. Currently, it continues to produce on average just above the type curve of 2 -- 1.2 million barrels equivalent.

We are very pleased that in early July, we added our second drilling rig. It is a top hole rig, drilling the intermediate string of casing and then we follow that with a bigger rig for the horizontal lateral. This method of drilling should improve our overall drilling cost structure, while still achieving appropriate spud counts. The Palmer 2-well pad is currently completing. The frac-ing on that should wrap up today and we anticipate first sales on this 2-well pad sometime early September.

Let me update everybody on the Garvin pad performance. To begin, the midstream downtime we experienced has been corrected and we have good sustained production on all 3 wells at this time, but we did have some fairly significant impacts to our production in the second quarter due to these midstream issues. As you can see in the gray portions of the decline curve, these are the shut-in periods and again, second quarter was dramatically affected in late May, and most of the month of June. But you can also see when the wells came back online, we reestablished production just above the type curve. Currently for the -- the average for this pad is right in line or just above our 1.2 million-barrel equivalent type curve that we presented at Analyst Day.

I would like to remind everyone that these reserve levels -- these are wells delivering very strong drilling economics and we feel the southern acreage will provide drilling returns, which will compete with the Wattenberg Field.

An overview of the drilling activity for the quarter. Again, we will be focusing on turned-in-lines or what we refer to as TILs, as our primary measurement of drilling pace, but I will also be communicating spuds for each quarter. From the bar graph, you can see we turned-in-line 28 wells for the quarter with a plan of 33, so right in line with our overall guidance, year-to-date spud counts by area. Wattenberg, we have 40 horizontal turned-in-lines and 55 spuds. In the Utica, 2 turned-in-lines, those are the Garvin wells, and we have spud 5 wells. And then in the Marcellus, we have 4 wells turned-in-line, the Armstrong-Reynolds pad, which was actually drilled in 2013.

From a non-operated perspective, we have 22 wells turned-in-line at an average working interest of 22% and we have spud 42 wells. We are on target for our overall drilling activity for the year, gross operated and non-operated combined spuds of 221 wells and 177 wells will be turned-in-line.

Again, quick review of our drilling activity. 5 rigs in Wattenberg currently running, 2 rigs in Utica, for the company a total of 7 drilling rigs.

Lease operating expenses. For the second quarter, total lifting cost came in at $4.28 per equivalent barrel, slightly higher than guidance. Let me give causes for this slight increase. First, labor costs in the basin have been growing, primarily due to the demand for labor across all services; drilling, completion and production operations. Second, additional compression costs, some related to higher line pressures we've experienced over the last year, and ongoing lease compressors we call VRUs that are capturing emissions under the new emissions rules. And third, ongoing increase in general EH&S areas, a cruise and additional regulations that are adding to our overall cost structure.

For the balance of the year, we expect lifting cost to hold just a notch over $4 and you can see this in our forecasting in the third and fourth quarters. Expect overall on a per unit basis, these numbers through 2015 and '16, we expect to improve as we dramatically increase our overall production base.

An update on our capital budget. Our total capital budget of $647 million, we announced last December, we're right on target for that budget with a few moving parts within the individual basins. First, we're about $30 million less in total in the Wattenberg. Currently forecasting about $443 million, that budget number is slightly lower due to fewer non-operated dollars and projects in the fourth quarter, primarily the 26-well Niobrara down space tests that we are partnering on with Noble Energy. That is now scheduled for the first quarter of 2015.

Second in the Utica, the original budget was $162 million, drilling completions and leasing has been revised to $192 million. The bulk of that increase is due to additional acreage acquisitions.

Overall, we're very pleased here. Our budget is holding in line with guidance. Our production has been upgraded by over 10%, and our Utica acreage position is growing faster than we anticipated within the original budget.

So operating highlights for the company. Wattenberg operated production. 85% of that in Wattenberg is now operated, 15% is non-operated. 55% of our operated production is now from our horizontal drilling program. The second quarter net production level of 23,300 BOE per day is record-setting for us. We drilled 20 horizontal Niobraras, 11 horizontal Codells in the quarter, very pleased our cost structure is holding at 4.2 million. We're drilling our first inner core well as we speak and we have 20 long lateral projects planned for the year.

In the Utica, 67,000 acres, very pleased with that number. Most of the acreage is in the liquid-rich window, which drives additional improved economics. We're focused right now on bolt-on acreage acquisitions, continued strong stabilized production from the 13 wells currently online, and our drilling and completion costs are $9 million per well and that is for an approximate 5,000-foot lateral.

And then the Marcellus, the sale of our 50% interest in the Mountaineer joint venture that we announced in late July, sales price of $250 million, that is net to PDC. The transaction is expected to close in mid-October. And Lance is going to give a lot more detail on that in a moment.

So with that, I'm going to turn this over to Gysle and let him cover the financials side of the business.

Gysle R. Shellum

Thanks, Bart, and good morning, everyone. Thanks for joining us today. As always, my comments will be high-level. So for complete analysis, please see our press release and our 10-Q, which was filed earlier this morning.

The second quarter was another very solid quarter this year. Net production for the quarter was 22.7 million barrels of oil equivalent, which was above the high point of our second quarter guidance. As Bart discussed, we have had better performance both in timing and turning wells in line and in well performance. We have also seen non-op production half performed our forecast, due to higher first half activity planned. Marcellus production was also above budget due to solid performance from the Armstrong-Reynolds pad that was turned-in-line around the beginning of second quarter.

Offsetting that somewhat our Garvin wells in the second quarter. We're still constrained a little due to the third-party pipeline issues that Bart covered.

Some highlights of the summary. Financial information. Oil and gas sales for the second quarter were under -- were just under $140 million, an 80% increase over the second quarter 2013, and about an 8% increase over the first quarter of 2014. The increase compared to the second quarter last year was mainly due to higher production with slightly higher commodity prices. Our average per barrel of oil equivalent price of $51.78 in the second quarter of 2014, was 10% higher compared to the second quarter of 2013, driven mostly by NGL prices at 17%. These prices do not include settlements on derivatives, formerly called, realized hedge losses or gains, which were negative about $10 million in the second quarter of 2014 compared to a positive $4 million in the second quarter of 2013.

Production costs increased about 66% quarter-over-quarter. Production costs include lifting cost, taxes, overhead and beginning this year, separate line item for fees associated with gathering, transportation and processing, specifically for Utica and Marcellus areas.

In the second quarter of 2014, production cost averaged $9.90 per BOE, $0.07 or 1% higher than the second quarter last year. For the first quarter 2014, we averaged $8.83 per BOE, so we were up $1.07, quarter 1 to quarter 2.

Lifting costs on a per unit basis were up 2% in the second quarter 2014 compared to the second quarter of 2013. The compared numbers for last year were all adjusted for the change in presentation for gathering, transportation and processing costs. Gross margins were 81% of sales for the second quarter compared to 79% for the second quarter of 2013. This reflects the increase in average prices before realized hedge gains and losses. Increased liquids production as a percent of total production offset by higher production costs also contributed to the slightly improved margin. First quarter 2014 margins were slightly higher at 84% of sales due to slightly lower production costs in that quarter.

DD&A includes depreciation of fixed assets and depletion of oil and gas properties. DD&A in the second quarter was up in total due to increased production and slightly higher rates. Depletion rates on oil and gas properties only excluding depreciation were $19.37 per BOE in the second quarter of 2014 compared to $16.14 per BOE in the second quarter of 2013.

G&A costs in the current quarter were up in total on a per BOE basis primarily due to the litigation charge of $20.8 million related to the ongoing class-action lawsuit that is now scheduled for trial in September. I'll refer you to Note 9 in our 10-Q for a broader description of this litigation.

The next slide represents non-GAAP financial information that is reconciled to GAAP in our 10-Q and press release filed earlier today. Additionally, we have shown the impact of the litigation charge I just mentioned on the non-GAAP information presented. Adjusted cash flow from operations was defined as cash flow from operations excluding changes in working capital, the upward trend here reflects that production volume growth had pushed oil and gas sales higher for the periods presented.

Adjusted EBITDA in the quarter was up about 16% compared to the second quarter of 2013 and down about 18% from the first quarter of 2014, largely due to the litigation charge in G&A.

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 in the second quarter of 2014 compared to the second quarter of 2013. Adjusted for the litigation charge, adjusted net income would be approximately $11.4 million or about $0.32 per share in the quarter ended June 30, 2014. Adjusted cash flows from operations would be about $76 million as Bart mentioned or about $2.12 per share.

In 2013, we extended the maturity of PDC's revolver to 2018 and have maintained the borrowing base at $450 million, all of which is undrawn at the end of the second quarter. We did not seek redetermination in May and with the expected proceeds from the divestiture of our Marcellus assets, we could choose to hold the $450 million in November, our next redetermination day. We exited the quarter with $40 million in cash, which along with cash flow from operations and the proceeds from sale, I just referred to, is expected to fund all of our 2014 capital programs. The table on this page reflects PDC's consolidated borrowings. Our consolidated financial statements included our proportionate share of the Marcellus joint venture debt, which was drawn $62 million to PDC's interest at quarter end.

The joint venture debt is nonrecourse to PDC and doesn't count against our $450 million borrowing base. This debt is expected to be repaid as part of the purchase of our joint venture interest. PDC liquidity at June 30, including cash on hand and available borrowing base, was approximately $478 million.

Our hedge positions for 2014 to 2015 and 2016 are shown on this next page. We've hedged substantially all of our oil and gas production that we are allowed to hedge under the terms of our credit agreement for 2014. For 2015, about 80% of our allowable production is hedged based on our year end 2013 reserve report. We're working on adding to our 2016 positions, and recently added some oil slots and 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, we'll move up over time. Our gas hedges are up -- are all in, in the $4 range for the 3 years. We settled a little higher -- at little higher prices during the second quarter this year. But as you all know, gas prices have weakened considerably of late, and our gas hedges are now about NYMEX on average. All of our hedge positions associated with the Marcellus joint venture will be sold to the buyer when we close. On a percentage basis, we expect our post closed hedge volumes for PDC to be very close to the consolidated hedge percentage, I just mentioned.

Bart walked you through the increase in our production guidance earlier. I want to provide you with updated financial guidance for the full year 2014. Blue column in the middle of the page shows the guidance numbers we provided at our Analyst Day. Two green colors to the right show our new guidance range based on annual production of between 10.4 and 10.6 million barrels of oil equivalent.

I'll point out the major items. Adjusted revenue is up around 10%. Adjusted EBITDA, up nearly 30% and adjusted net income is up 80%, while adjusted cash flow from operation remains basically flat. The significant events that are impacting this guidance are: first, we are factoring in the results from the $250 million sale of our Marcellus joint venture interest, which is expected to close in October. We estimate an $88 million book gain on this sale, which will result in an increase in taxes of approximately $15 million. If there are downward adjustments to the purchase price, we'd expect the gain in the tax obligation to decline accordingly.

Gain on sale shows up in adjusted EBITDA, pretax and adjusted net income after tax, but not in cash flow. The tax impact related to the gain shows up in adjusted cash flow and adjusted net income. Secondly, the litigation charge, I mentioned earlier, reduces adjusted cash flow and EBITDA by 21.4 million pretax for the full year, including the $3.3 million charge taken in the first quarter this year. It also impacts adjusted net income by about $15 million after tax. When we look at our cash on hand at June 30, our forecasted cash flow and capital expenditures in the second half of 2014, we believe we will exit the year with 0 or very little drawn on our revolver, assuming the sale of our Marcellus joint venture interest closes this year.

With that, I'll turn this over to Lance.

Lance A. Lauck

All right, thanks, Gysle. Last week, we announced the signing of definitive agreement to sell our 50% interest in the PDC Marcellus joint venture for approximately $250 million. This sale is important to PDC for 2 key reasons. First of all, it completes the company's transition to a liquid-rich set of assets. We're now fully focused on horizontal development in the high-return Wattenberg and Utica Shale plays. Secondly, proceeds from the sale results in the company being essentially undrawn on its revolver at year end 2014, and it substantially improves our debt metrics over the next 3 years.

As we stated earlier, the pending Marcellus sale is anticipated to close on or before October 15, 2014. Our estimated before tax proceeds are approximately $190 million and that's after our net share of joint venture debt and other working capital adjustments. Operationally, the assets represents 240 Bcf or about 40 million barrels of net proved reserves as of year end 2013. That being comprised of approximately 99% dry gas.

The Marcellus assets produced about 26 million cubic feet a day equivalent net during the second quarter of 2014. Additionally, net leasehold in Marcellus is approximately 65,000 net acres.

Additionally, the buyers assume PDC share of the firm transportation obligations, as we all talked about earlier, as well as natural gas hedging positions for 2014 and 2015.

The Marcellus Shale results in several positive impacts to PDC's portfolio. It increases the liquid mix of our proved reserves and improves both our per-unit PV10 values and gross margins. As shown on this slide, our pro forma year end 2013 proved reserves increased from 54% to 63% liquids mix. Additionally, our SEC PV10 per unit value increases over 10% to $11.50 per BOE, high grading the quality of our proved reserve portfolio. And then finally, our 2014 pro forma gross margin increases by over 10% to approximately $48.60 per BOE by excluding Marcellus volumes from our updated 2014 production guidance.

The next 3 slides provide our updated 3-year outlook. The copper bar graphs represent our projections from our April Analyst Day, while the blue bar graphs represent today's updated outlook. The cross hedge pattern at the top of each bar graph represents the range of results.

Our updated long-term production growth increases to a range of approximately 31% to 38% per year through 2016. This compares the April Analyst Day range of about 30% to 36% per year. This updated outlook makes 3 adjustments to our April Analyst Day assumptions.

First of all, we exclude all Marcellus volumes after our planned closing date of October 2014. Secondly, we incorporate the Wattenberg outperformance in the future forecasts and then finally, we update the pricing projections for the June 30 NYMEX Strip. I want to note several key takeaways. By 2016, our updated production outlook exceeds our April Analyst Day outlook, despite having sold the Marcellus assets. This is due to the outperformance of the Wattenberg capital programs. Secondly, the updated projections keep rig counts and capital spending in Wattenberg and Utica the same as our April Analyst Day. As you may recall, we projected 5 rigs in the Wattenberg in 2014, 6 in mid-2015 and then 7 rigs in mid-2016. While Utica was projected to pick up its second rig in mid 2014, and then be held flat at 2 years -- at 2 rigs for 2015 and '16.

If we were to remove Marcellus in all 4 years on the slide and only forecast Wattenberg and Utica, the compound annual growth rate would increase to a range of 40% to 46% per year from 2013 through 2016, showing a tremendous strength in growth opportunity at these 2 key basins. Additionally, our 3-year liquid mix over the 2014 to '16 timeframe is expected to increase to approximately 69% given the pending sale of the dry gas Marcellus assets.

The next slide highlights our updated cash flow per share outlook. Our cash flow per share outlook exceeds our April Analyst Day in both 2015 and '16, and is projected to grow on a compounded annual growth rate of approximately 34% to 40% per year over the 2013 to '16 timeframe. This compares to a range of 30% to 37% compound annual growth rate at our April Analyst Day. In 2015, next year, the company projects cash flow per share at over $12 per share or over 50% growth versus that of our cash flow per share in 2014. This is a result of our 100% focus on growing our liquid-rich horizontal wells drilled and turned into sales.

Finally, our earnings per share outlook in all years are projected to exceed that of Analyst Day.

Our 2014 earnings per share of approximately $2.50 includes our projected gain on sale at Marcellus. Our 2015 and '16 earnings per share forecast exceed Analyst Day due to our exclusive focus on high-margin liquids development.

This final slide presents one of the best impacts of the pending Marcellus sale. Our overall capital spending over the next 3 years is now slightly less than that of Analyst Day, given that Marcellus capital is excluded after October 2014. But most importantly, our year end debt metrics are substantially improved from Analyst Day, showing our commitment to maintaining a strong balance sheet alongside our exceptional future growth projections. We now project that our year end debt-to-book cap to drop by about 7 percentage points and all years to about 37% in 2014, and then finally 39% in 2016. In the same way, our year end debt-to-EBITDAX is reduced to a range of 1.5 to 1.3x, much improved from the April Analyst Day projections.

So to summarize, PDC has fully completed its transition to liquids. We have a substantial inventory of over 3,100 locations in 2 of the top return plays in U.S. onshore. We're committed to maintain a strong balance sheet and we're focused on long-term shareholder value growth.

And with that, I'll turn it over to the operator for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from David Tameron with Wells Fargo.

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

Can you guys just talk about gas on the quarter? What -- it looks like gas came in pretty strong, what was driving that or are we just assuming the wrong thing on our own?

James M. Trimble

The gas actually came in a little bit higher on our models relative to our guidance. Three things going on here. First of all, our non-operated, what we modeled, the actual projects that we have partnered on are more in the middle, in inner core areas, so we've got a more gassy mix in the Wattenberg coming from the non-operated productions. So not only is the gas here, but those volumes are also much, much greater than we anticipated, as I called that in my discussion. Second thing is our Marcellus team did a really outstanding job in the quarter. I believe their production relative to our expectations was 8% to 10%. And again, that's a dry gas play. And then the third thing, David that happens is our Codell wells, coming on very, very strong and they are exhibiting a -- higher GOR in the same area than the Niobraras. So what we modeled, we're getting a little more gas production out of the Codells early time. So those 3 forces have driven our gas production to be just slightly higher. I will say we're not concerned because the economics behind those inner core and middle core wells, if you go back to the Analyst Day, were the strongest economic projects there. So those are the 3 pretty big things.

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

Okay, so just to throw it out, I mean, there's been some concern that the GOR in the existing production is moving. Is that -- are you seeing that or is -- from Niobrara, are you seeing any change to that thing kind of some of the chatter on the street?

Barton R. Brookman

No, there's no GOR. I mean, the production from the Wattenberg is so firmly understood with years of history in both these reservoirs. We are not seeing any changes in our GOR in the Wattenberg. In the Utica right now, stabilized production on our producing wells. We are not seeing a dramatic shift in the decline. And we are not seeing a dramatic shift in the GOR. So those -- we get a lot of questions in the Utica around that, so.

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

Okay. No, that's helpful. One more and then I'll let somebody else jump in. On the acquisition front, are you guys looking -- I know you're always looking to add, but in the DJ and the Wattenberg, I'm thinking about Cruz[ph] has got a package out there and other -- some of those small operators who could be consolidated. How do you guys feel about your current -- I know you like your current position, but how do you feel about expanding that? And can you give us some thoughts around that?

Lance A. Lauck

David, this is Lance. In the 2 core areas, both the Wattenberg core and then the Utica, we're both looking for bolt-on opportunities in those 2 positions. And so as we highlighted last week, we've added the 13,000 acres in the Southern Utica, providing bolt-on and really more efficiencies, so that we're able to drill more wells on the acreage position that we have. And so look first to continue to do more of the bolt-on types of things in the Utica area. And then as well as on the Wattenberg, as we look at different opportunities in the Wattenberg, we will look in and potentially pursue those, David. But they're going to have be something that's in the core area of the field, something that bolts on to our acreage and provides additional efficiencies for our company.

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

Okay, so you're not -- Lance, you're not looking to move kind of northeast?

Lance A. Lauck

No, we're staying in the core areas, the field, I think as demonstrated by the tremendous outperformance of the Wattenberg here in this quarter, it's a great place to be, and its one where our teams are focused. And we think we've got the best operational efficiencies in the core area.

Operator

Our next question comes from Irene Haas with Wunderlich Securities.

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

And my question for you is, when would you be going back to work on the Neill well? Do you still feel about that particular acreage the same way you still stick with your existing map of the wet gas that was sort of have shifted west? So I just want to get your outlook on this.

Barton R. Brookman

Yes. And I don't think we have anything right now that says we want to move the phase behavior that we've presented at Analyst Day, and that was in the presentation. So we're sticking with that. The Neill well continues to be a disappointment. As I've outlined in the market, our landing zone, we were low relative to the Point Pleasant number. It's currently on rod pump. We're trying some other production methods to enhance the production of that. But the GOR and the pressure data we obtained off that well is extremely encouraging. It's really not that far from the Palmer well, so we're highly anticipating. And I just want to clarify one thing, the Palmer wells are not on -- I think you said online. We just finished the completion on those. We anticipate they'll be online in early September. But the Palmer data is going to be key for the company because it really is going to provide data points for that -- additional data points on top of the Garvin wells for all of that southern acreage.

Operator

Our next question comes from Welles Fitzpatrick with Johnson Rice.

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

Does White Cliff FERC ruling affect you guys at all?

Barton R. Brookman

Yes, so -- yes, wells on the FERC ruling on the White Cliffs Pipeline does vacate our volumes that we had anticipated there. We've noted that it was 10,000 barrels a day, and we also noted that was subject to FERC approval. What did FERC has asked White Cliffs to do is to provide an open season for the space. And so we plan to participate in that open season that they have coming up.

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

Okay, perfect. And that's later this month. Am I getting that right?

Barton R. Brookman

That's my understanding. It's supposed to be later here in the month of August.

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

Okay, great. And then on the Sunmarke and Chestnut pads, it looks like you guys have started reaching TDs on some of those? Are we going to get those in the fourth quarter?

Barton R. Brookman

Oh boy. Probably not. I think I have to look at the completion schedule of those wells. I think that's probably coming on late in the year. And for us to have any real data to talk about, I think it's probably going to be early next year.

Operator

Our next question comes from Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Guys, can you provide any update on the performance on the wells of the Waste Management pad? Are you seeing any interference yet on any of those wells?

Barton R. Brookman

We have not seen any interference, but wells are -- what we presented at Analyst Day and since then in the market presentations, Leo, we are extremely pleased with all 16 wells. The Codells and the Niobraras are performing very close together, and they are very in line with the "middle core region type" curves. And we have -- I believe we have one additional stages test there. We continue to evaluate that. We continue to get questions around that. That well early production was stronger than the other 15. And the decline within a few months, down very close to the other wells, we're really evaluating the additional stages on that one, the contribution and the extra dollars relative to the long-term decline on that well. So all good news from Waste Management.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. Can you guys provide some more color on your earlier comments on the call where you saw some gassier production from the Codell. Is that just across the board? And your acreage, was that more localized and some maybe more recent areas of drilling?

Barton R. Brookman

With -- here's the general kind of satellite view of what we're seeing. As we go to the middle and inner core area in the Codell wells, and you've got the more thermal and mature portion of the basin and a little bit cleaner Codell and it's a little bit higher pressure. We are seeing the gas volumes come on in the Codell is very strong. So that trend is greater as we move more towards the inner core region. So yes, we've got additional gas from our modeling. Next year, when we do our guidance and our budget, we'll try to incorporate all of this into our type curves, but we are definitely seeing that more in the gassier portion of the basin, which makes sense when you get in the relative permeability and a lot of different things. But that's a trend we're seeing. Probably not as severe in that outer core region; more severe as we move to the inner core.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right, I guess just jumping over to the Utica. I think you guys have been working on some potential firm takeaway deals of your gas. Do you have any update on that?

Lance A. Lauck

Leo, this is Lance. So yes, in Southern Utica, we're in the very final stages of executing an agreement with Blue Racer for this acreage position. It will be an acreage dedication, and all the key terms already agreed to do. We're just in the final stages of executing the document by both parties. So we are in a good position with that, and that'll be something that'll be effective here very soon.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful. And I guess just following up on the question regarding gas, oil mix. I know you gave a number of reasons why the gas mix was higher this quarter. But just specifically at Wattenberg, I mean, was there anything that was holding back any oil volumes or anything like that in the second quarter? I mean, look at the sequential growth, that saw the oil was up 5% in Wattenberg and gas is up 29%. I know you had worn-off gas and better Codell performance. But was at all constraining the oil volumes in the quarter?

Barton R. Brookman

No. No, the only thing that we had to talk about or gathering out there in June, is when we saw some warmer weather in mine pressures due to the warmer weather start coming up a little bit. Overall, for the first half of the year, we've been pretty pleased with DCP and their gathering performance. So our oil production has been setting records. And -- so again, the trends I gave as far as non-operated, our Marcellus is a big chunk of that, and then the Codell is being a little bit gassier. Those are the big 3 related to the gassier production for the company. I do believe, Leo, in Lance's presentation, I think he had a good outline of where we're headed on a 3-year forecast post sale of the Marcellus. And I believe it was 63% liquid mix.

Lance A. Lauck

Yes. I guess it gets as high as 69% over the next 3 years. But Leo, also keep in mind that the quality of this gas at Wattenberg is a very high BTU gas, and so it's a great valuable commodity there coming out of the Wattenberg. So as we go towards the middle and inner core areas we're drilling, as Bart talked about earlier, we have our best economics in those areas.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. I guess just one last question on the taxes. You guys said you're going to be paying some taxes on the gain on sale in the Marcellus there. Are those going to be cash taxes or is that going to be deferred?

Gysle R. Shellum

They will be likely paid in next year. So it's -- it will be a cash impact that will accrue this year and paid next year.

Operator

Our next question comes from Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So on the litigation, could you talk about the basis and the math behind your initial $3.3 million liability? And then the follow-up, $20.8 million charge?

Gysle R. Shellum

Sure, Joe. This is Gysle. I can't talk much about it because it's ongoing litigation, but I can give you a flavor for the accounting rules on this type of thing. On contingencies, if you have an event that is greater than a remote chance of happening but less than a probable chance of happening, you're required to, if you -- if you can, disclose an estimated range of impact. So that is what we have done here. And you're also required, if you could estimate it, a probable or a possible impact and accrue that in the current quarter. So the amounts we accrued are estimate of a possible impact. That's not probable, it's -- and there's a lot of subjectivity there. So that's what we've attempted to do in the accrual and in the disclosure in the 10-Q with the range there. And that's really all I can say about it since it is ongoing litigation.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, got you. So -- and then I think the plan that you're seeking $175 million, I'm not sure if you've seen any document that goes over the math behind that. Do you have a rationale for that number?

Gysle R. Shellum

I can't talk about that, no.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, I got it. Right. On a different topic, in the Wattenberg, I know you're trying some new completion designs. Do you have any initial results there in terms of what's the increasing cost? What's the early uptick in production?

Barton R. Brookman

Oh boy, I could go through multiple. And Joe, it probably -- it depends. Yes, most of the completion techniques right now that we're trying add additional cost. Let me walk through probably the big ones. The longer laterals are obviously going to be somewhere between $500,000, probably $1.5 million depending on how long that lateral length in the final completion design. Obviously, we are pursuing reserves that will lower total drilling F&D cost and enhance the economics. And Scott and the Wattenberg team continue to evaluate those projects. We have some early data. We really feel like the end of the year will be when we'll have enough to come back to the market and show the benefits of that particular well design. The second major completion design we have is increased stages per -- shorter stage length or increased stages per a thousand foot. We've got a variety of tests, I think 25 of these pilots this year. We're looking for, as I discussed on the Waste Management pad, a higher IP and maybe a lower long-term decline from those. Those are about $500,000 depending on the actual stage density, more per well. Once again, we need reserves to offset those costs and drive drilling F&D down. We have surfactants. We have proppants. And probably the biggie we're getting a lot of questions right now are plug-and-perf jobs. I know there's -- some of our peers have recently been in the market talking about this. We reviewed plug-and-perf in all of our basins extensively. In Wattenberg, we've made a commitment to the sliding sleeve jobs for a variety of reasons, but we continue to look at the cost structure and new technology and data. And I believe the team right now, this year, has 5 plug-and-perf jobs planned. Those will cost we think about $500,000 more per well. So it'll be late. Again, all 3 of these pilots, I think it's going to be late fourth quarter when we can be back in the market saying, "hey, these completion designs are really delivering additional value back to -- or performance on our drilling and completion programs." So anyway, a lot of words there but hopefully, I answered your question.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

No, that's helpful. And then lastly, are you looking to do any Niobrara A tests?

Barton R. Brookman

Two for 2014.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, got you. Okay, but you haven't done any at this point?

Barton R. Brookman

We've done 1 of the 2.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. Any results you can talk about there?

Barton R. Brookman

No, don't have them off the top of my head.

Operator

Our next question comes from Ipsit Mohanty with GMP Securities.

Ipsit Mohanty - GMP Securities L.P., Research Division

If I might just go looking granular and ask you for a month-wise breakup of the 17 TILs in Wattenberg or at least were they front-end or back-end loaded to the quarter?

Barton R. Brookman

I apologize. Can you repeat the question one more time?

Ipsit Mohanty - GMP Securities L.P., Research Division

Oh, I just wanted a month-wise breakup of the 17 TILs in Wattenberg. If you have that.

Barton R. Brookman

The 17 -- the turned-in-lines in the quarter?

Ipsit Mohanty - GMP Securities L.P., Research Division

That's right, of the horizontal Wattenberg.

Gysle R. Shellum

I don't think we've typically given monthly.

Barton R. Brookman

Yes. I don't think we have the monthly TILs.

Ipsit Mohanty - GMP Securities L.P., Research Division

Would you comment that it was more back-end loaded than front end?

Barton R. Brookman

The original model was more back-end loaded on TILs. And part of our enhanced guidance and upticks that I gave, is we have had some shifting more earlier in the year.

Ipsit Mohanty - GMP Securities L.P., Research Division

Got you, got you. And your non-op increased a little bit more from the first quarter. Is that how we should model going forward, probably 15% rather than 13%?

Barton R. Brookman

Yes, I think you can build off that and you can expect an increased pace, and I gave the total TILs of non-op. And I think it's fair to assume that 20% to 25% average working interest is a fair assumption. The big thing that is difficult for us and difficult for the market is where are these projects going to be in the field. It's very easy for us to model our drilling programs because they are mapped and permitted out for the next year, 1.5 years. But the non-operated projects sometimes have 3- or 4-month turnaround after we signed the AFE.

Ipsit Mohanty - GMP Securities L.P., Research Division

Got you, very helpful. And then one final, what was the volume impact, if any, from high line pressure?

Barton R. Brookman

The first 5 months, very little. We saw -- when the O'Connor plant started in October of 2013, we saw a fairly dramatic reduction in line pressures. I think we had the best quarter, first quarter that we've experienced. In second quarter, that continued. And as we came off winter and we saw freezes free up and lease use go away, the burners were being snuffed on the leases, so that there was more gas on the gathering system, and warm weather showed up. And the drilling programs continued. June, we experienced higher volume pressures on DCP. The good news is for the market, I think we had a good understanding of all this. We modeled it correctly, and we feel right now, we have very good understanding of where we're going the last half of the year. And we have modeled this appropriately in our revised guidance.

Operator

Our next question comes from Brian Corales from Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

I think most of my questions have been answered, but just a follow-up to Joe Allman's question on the different frac changes or testing that you all are doing. I mean -- so have you all had a lot of nonoperated activity with different completions or is all this new to you?

Barton R. Brookman

Slightly, Brian. But probably not enough for us to go start making conclusions. I think the one thing is we do have some longer laterals that we have participated in. And so we've got that data that we're starting to get. But most of what we want to do will be generating through our operations. We always look at our peer data, especially from a reserve standpoint. But some of the data that we review on the non-operated, there's a mix of things going on. So we really want to get this in-house. And like I said, I think by the end of this year, we're going to have a really good report back to the market of the different performances.

Brian M. Corales - Howard Weil Incorporated, Research Division

So can you maybe comment on -- if you're seeing -- I know the costs are going to be more, but you are seeing beneficial improvement from the productivity of the wells?

Barton R. Brookman

You're talking about on the non-operator?

Brian M. Corales - Howard Weil Incorporated, Research Division

Or on operate. I mean what you're testing right now? I mean, are you seeing the better production?

Barton R. Brookman

Yes. I would say the answer is, yes. And the question and the thing we are really evaluating before we jump out and deliver too strong of a message on this is, a lot of this is related to the long-term decline of the wells. The longer laterals in the extra stages, we believe are going to give some IP, but is it going to -- that demax, is it really going to impact that? So that's something we need 6 months of data for our team to evaluate.

Operator

Our next question comes from Michael Hall with Heikkinen.

Michael A. Hall - Heikkinen Energy Advisors, LLC

I guess one thing I just wanted to circle around on. You got obviously, credit [indiscernible] moving pieces in the guidance, particularly on the cash cost guidance in 2014. It looks like that's up a bit relative, obviously, to the prior guide. You talked about some of the items impacting that. How is that assumed to progress through the 2015 cash flow guidance that's provided? And I guess, also in that context, the cash margin, as you've seen the mix shift with the Marcellus sale on 2015, how is that cash margin excepted to behave?

Gysle R. Shellum

I'll take the first shot at this. This is Gysle, and I'll pass it on to Lance for the forecast. So for 2014, we took the -- really, the ending rate, the exit rate for the year, and then obviously, stripped out the Marcellus contribution to cash flow. And that was our starting point for 2015. Obviously, that changed our liquids mix, improved our liquids mix going forward, improved our margins going forward. And then as you mentioned, there's a lot of noise in the forecast this year for the gain on sale, taxes and the litigation that's -- that we don't expect to incur going forward. So Lance, you have anything to add to that?

Lance A. Lauck

Just on the cash margin, sort of gross margin going forward. On the slide there, Mike, we talked about -- if you look at our 2014 updated guidance for this year that we have just come out with and if you subtract out all of the Marcellus volumes from that, then you see a gross margin based upon just Wattenberg and Utica of about $48.60 per barrel. And that's -- so that's the gross margin based upon what we see as the NYMEX pricing on average for 2014. So I think from that, you can kind of look at that margin and kind of project forward based upon the NYMEX strip how that kind of compares going forward over the next couple of years. But overall, we see this is about a 10% increase in the gross margin now having the Marcellus out of the mix on a go-forward basis.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Okay, that's helpful. I guess just to drive down a little bit on the cash cost side per unit, are you expect -- are you modeling in with that guidance material improvement in cash cost that's relative to what's supplied by the second half of '14 guide? Or do you think there's some potential upside as you get some scale as you continue with the volumes nicely in 2015?

Barton R. Brookman

Let me see if I can tackle this one, Michael. We expect the G&A of the company to grow as we go in the next year. We're adding talent, we're adding some really high-quality talent. Our field operations is growing significantly. And as I discussed in the LOE, we do have some EH&S, obviously, what's Colorado regulations, the air rigs and some labor, called labor demand pull forces in the market. So those are going up. So yes, on a cash basis, you will have those increasing where we've got very strong efforts in the company to manage those effectively. And -- but those costs will go up what we think at appropriate levels. That's offset by our production gains that we're going to be adding. So on a unit basis, both G&A and LOE, we expect -- and I think I covered this in my comments, we expect on a per -- BOE, we should see significant reductions on a per unit in our G&A and our lifting costs as we go through 2015 and 2016. We think this is a measurement that we should strive to improve. And our models right now say we will improve. So hopefully, I'm answering your question. We're going to grow this company. And we're going to be adding people. And we recognize there are parts of our businesses that are getting more expensive. But the offset to that is we have tremendous return projects that are going to be adding production and tremendous cash flow. And that will more than offset the increases in the costs.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Yes. All right, that's helpful. And then is that significant improvement per unit, like low double-digit-type improvement? Or any quantification of that?

Barton R. Brookman

Yes. I don't have that model right in front of me. I know it's built into Lance's models. And I can tell it’s built into the cash flow forecast that he just presented to you, guys.

Lance A. Lauck

Right.

Operator

Our next question comes from Mike Scialla with Stifel.

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

Bart, you'd said you'd like to see some more data on the long laterals before you -- I guess you really kind of need to get a fix on the shape of the decline before you make a decision there. Say, that turns out to be favorable, I know some of your acreage is a bit checkered, maybe not conducive to drilling a lot of long laterals. How would you go about -- I guess, just a follow-on, maybe, to David Tameron's question earlier. There are some opportunities maybe with some privates or is there -- are there any opportunities to do swaps or would you just partner up with somebody to get longer laterals drilled?

Barton R. Brookman

Yes. I think the first piece of that equation is we need to see dramatically improved economics. And if that were the case, Mike, then we would turn around. And most likely be approaching our neighbor acreage leaseholders and try to pull the acreage into a longer-lateral project. Some of that is what is happening on some of our non-operated projects currently. So we're being approached, and then we would counterpunch. And approach them with the same technique. So again, I think that is something -- we've got to get more data because we do have some -- I mean, we've got some good data on this and there were some mixed results right now. And there's obviously increased costs. And very important for the market, there's increased risk when you start talking about 7,500- or 9,000-foot laterals. If you can't get a liner down, if you have a drilling problem, for a company like PDC, it's a fairly significant event if we were to lose a wellbore. So we try to incorporate into our business plans that mechanical risk also of those longer laterals. So Mike, hopefully, I answered your question.

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

Yes, you did. I appreciate that. Just one other -- on the second half production increase, the 300,000 BOE, can you say where most of that is attributable to? Is it timing, performance or? And where?

Barton R. Brookman

Mostly Wattenberg. Timing and performance, it's a good blend of both of those. We try to break that operated performance separate the 300,000 from the non-operated, which I believe was 200,000 -- I don't have -- it's 200,000 barrels.

Operator

Our next question comes from Jason Smith with Bank of America.

Jason Smith - BofA Merrill Lynch, Research Division

Can I ask you -- if you don't mind, if you can just maybe tell us what you're seeing today in terms of differentials, both in the Wattenberg and in the Utica? And what you've assumed in your forecast going forward?

Lance A. Lauck

Sure, so let's start with the Wattenberg, Jason. So for -- our well differentials there, we're about $12 per barrel off of NYMEX, and that takes you all the way back to the wellhead. And we've been trending that differential through the first, not only half of the year, but on into the next couple of months into the third quarter. So that's held very well, and we classify that as prive [ph] and stable throughout the rest of 2014. The gas differentials from CIG, as you'll note, are getting a little bit stronger, tighter, if you will, if you look at the second half of 2014. And that's just due to some tightness in the gas markets here in the Western U.S. and some up into Canada. So that's a positive sort of looking forward there a bit as well. Then on the Utica side, our condensate there for the second quarter has a differential balance about $8.25 per barrel off of NYMEX. And so we're right in line with our projections for the year out there in the Utica side of this. So that's sort of the differentials that we're seeing in those areas. The NGLs, if you will, and the Utica, is kind of a blend right now. There's a -- year-to-date, there's been a lot of propane plus that's been taken out. But they'll start to pulling out some methane as well, so we've got some moving parts on what the NGLs will look like there. But overall, the first half of the year, our differentials for NGLs in Utica was about 50% of NYMEX. Is that sort of answer your question, Jason?

Jason Smith - BofA Merrill Lynch, Research Division

Yes. And gas in Utica?

Lance A. Lauck

Yes. So gas in the Utica, if you look at the pricing point there, we're priced currently off of TETCO and 2. And we saw a differential NYMEX versus TETCO in the second quarter of about $0.92. I think for the first half of the year, that differential on average is about $0.57. As you know we had a pretty cold winter there in the first quarter of the year. We do expect the widening differentials to be here. And that will be something that we'll see probably in the second half of the year just given the strong supply of gas and just the progress to date on getting additional takeaway projects in place in order to get more gas out of the basin.

Jason Smith - BofA Merrill Lynch, Research Division

Thanks Lance, I appreciate the color. And maybe one for Bart, really quick. In Washington County, a bunch of the acreage you guys have acquired is a little bit further south than anything you drilled. Are there any plans at this point to go and test that acreage?

Barton R. Brookman

Oh, it's 2015, in the '15 drilling program.

Jason Smith - BofA Merrill Lynch, Research Division

Okay. And then one more maybe for Gysle. I know this is -- litigation, I know it's a little bit sensitive, so maybe I can try this and I appreciate it if you -- if you can't answer it, but you said in the 10-Q that trial, I think, September of this year. What are the next steps in mediation?

Gysle R. Shellum

All I can say is it's continuing.

Operator

[Operator Instructions] Our next question comes from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

We had a talk, thankfully, I guess, about frac pads or any of the regulatory risk in Colorado, obviously, with the deal announced this week. Just wanted to kind of get your thoughts there. Is that a done deal where the pro industry initiative still anticipated to make the ballot? Just any color you can provide kind of on the regulatory environment and how that's shifting for you in Colorado.

James M. Trimble

Well, I think what you can look at is, it is a done deal. The ballot initiatives are pulled. What the governor has asked for is I think is an 18-member task force that's going to be put together and its headed by the President of XTO. And it'll be a combination of the operators in the area. And I think what it'll be is a -- taking a look at sort of the concerns of the citizens, the concerns of the industry, concerns of the other parties that are involved here, I don't -- you're not going to look at anything that's going to be resolved this year. It’s going to be a long term. I think going forward, we'll be able to operate our programs as we are doing now. I think the 2015, '16 that Lance put out is not in jeopardy. And so we look for this to be a solution that's going to be a long term, and it'll be beneficial to everybody.

Operator

Our next question comes from David Snow with Energy Equities Inc.

David Snow

I'm wondering about the recent ruling to allow some condensate exports. Are you going to benefit both either in Wattenberg or Utica from that? And are you currently in line or where do you stand on that regard?

James M. Trimble

Obviously, I think that what you're looking at is directly affecting us. I wouldn't say it’s going to be anything that we're going to be do stepping out and taking a tanker and exporting. But I think it will help. And the people who are exporting freeze up other abilities for us to hit the market. So it's really -- the whole issue is still in question. For it to be exportable, it's got to have been processed in some manner. So there's still a lot of uncertainty about who will be doing it, and -- but I think that it's going to be much larger companies that are going to be doing that type of thing. But by then, exporting is, I think, will free up us the opportunity, in fact free all that.

David Snow

Are downspacing tests underway for more than the 16 per section?

Barton R. Brookman

Yes. Yes, sir David. We've got 3 in the company right now and I believe at Analyst Day, we presented 5 and 3 of those are this year. And those are approximately 20 well equivalent per section tests, both in the Codell and the Niobrara. We've got one of those in the middle core, one in the outer core, another one in the middle core and the fourth in the middle core. So a variety of tests across the basin. We'll be gathering a lot of data both in the Niobrara and in the Codell. And as I said, in the Codell, right now, we've got a few of those wells -- on those tests, so we have moved up to the Niobrara based on the tremendous performance we're seeing in the Niobraras as we migrate towards the inner core.

David Snow

Spacing, do you have any early reads on the 20 wells spacings?

Barton R. Brookman

No, sir. We're just drilling those projects now.

Operator

And our final question is a follow-up question from Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Just 2 quick questions. So back to the litigation. So Gysle, you talked about a range. So is the range you talked -- is the range that you're estimating your best guess at this point between the $3.3 million, which was the initial liability and now the $24.1 million?

Gysle R. Shellum

No, Joe. The range in the -- disclosed in the Q is anywhere from 0 to $175 million, which is the damages alleged by the finance.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, got you. So now the $24.1 million you've taken at this point, are you basing that upon what's going on in mediation? Or are you basing that upon what might happen given some probability analysis at the trial?

Gysle R. Shellum

Well, based on the accounting literature I mentioned to you earlier, that's just our best estimate at this time.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, got you. Okay. And a follow-up on the -- just the long laterals and the other changes you're doing. So Bart, I'm wondering if after you do your analysis, you realize that the returns might be lower, but you might get better net present value. Would that -- would it be worth going forward in that case?

Barton R. Brookman

If we have a project discounted at our cost of capital that's adding additional value to our stockholders, we will consider executing on that project. So hopefully, that answers your question, which those familiar with that analysis, you can have lower internal rate of return, but actually, at our cost of capital be delivering more value. And we absolutely consider that in our economic evaluation of our projects.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Great. And then you said you're expecting to give a really good report back to the market. And then you subsequently said that you've had some mixed results with -- I think you said you had some mixed results with the longer laterals. Can you just reconcile that?

Barton R. Brookman

I can reconcile that we've had a few projects that have not performed up to our expectations. So -- but we also have some encouraging data, and we really want to execute these in-house and get our own data, so that we can really, really have polished data and polished executed -- cleanly executed completions. And I'm not saying our peers didn't do that, but we've got different frac designs and different things we're doing.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you, okay. And then just a quick follow-up for Gysle, just a non-litigation question. Gysle, the notes that are due in 2015, what are the plans with that?

Gysle R. Shellum

Those are convertible, they're noncallable, so conversion price, I think, is $42.40. So we have the option of taking that out in cash or stock or a combination of the 2. We haven't solidified what we're going to do. We'll make that call when we get closer to that date, but it'll be more likely a combination.

Operator

At this time, I'm showing no further questions. I would like to turn the call back over to Mr. Trimble for closing remarks.

James M. Trimble

Well, thank you. And I'd like to thank everyone for joining us today and for all your support. And we look forward to catching up later. Thanks.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may now disconnect.

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Source: PDC Energy's (PDCE) CEO James Trimble on Q2 2014 Results - Earnings Call Transcript
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