SandRidge Energy's (SD) CEO James Bennett on Q4 2016 Results - Earnings Call Transcript

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SandRidge Energy, Inc. (NYSE:SD) Q4 2016 Earnings Conference Call February 23, 2017 9:00 AM ET

Executives

Duane Grubert – Executive Vice President of Investor Relations and Strategy

James Bennett – President and Chief Executive Officer

John Suter – Executive Vice President and Chief Operating Officer

Julian Bott – Executive Vice President and Chief Financial Officer

Analysts

John Aschenbeck – Seaport Global

Amer Tiwana – Cowen & Co.

Patrick Conner – Whitebox

Operator

Good morning. My name is Scott and I will be conference operator today. At this time, I would like to welcome everyone to the SandRidge Energy Fourth Quarter and Full Year 2016 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Thank you.

Duane Grubert, Executive Vice President of Investor Relations and Strategy, you may begin your conference.

Duane Grubert

Thank you operator, and welcome everyone. Thanks for joining us on the conference call. This is Duane Grubert, EVP of IR and Strategy here at SandRidge. With me today are James Bennett, our President and Chief Executive Officer; John Suter, EVP and Chief Operating Officer; and Julian Bott, EVP and Chief Financial Officer.

We would like to remind you that in conjunction with our earnings release and conference call, we have posted slides on our website under the Investor Relations tab that we'll be referencing during the call. Keep in mind today's call contains forward-looking statements and assumptions which are subject to risk and uncertainty, and actual results may differ materially from those projected in these forward-looking statements.

Additionally, we will make reference to adjusted net income, adjusted EBITDA, adjusted G&A and other non-GAAP financial measures. A reconciliation of the discussion of those measures can be found on the website. You will also see us file our 10-K next week. Please note the call is intended to discuss SandRidge Energy and not our Public Royalty Trust.

Now let me turn the call over to CEO, James Bennett.

James Bennett

Thank you, Duane. Welcome everyone and thank you for joining us. As I always like to cover on these year-end calls, I'll be laying out our strategy and talk about how our recent performance, cost reductions and innovations have set up a compelling shareholder value creation story. I'll also cover the roll-out of an exciting new 60,000 acre Northwest STACK, Meramec and Osage play and adjacent acquisition, our first Meramec well in Major County Oklahoma with an impressive 925 Boe per day IP, record low well cost in the Miss and developments in our Niobrara asset in Colorado, including our first extended reach lateral and the first C bench test.

Then John Suter will cover detailed operational update and our CFO, Julian Bott will give a financial update and we'll wrap up with any questions you might have.

Let me start with reviewing our strategy for 2017 and then touch on some significant execution steps we've made to put this strategy in motion. I'm going to start with referencing Page 3 of the presentation. We started publishing this page in October of last year and the strategy and the message have remained consistent. We have one of the strongest balance sheets among our peers, have high-graded our Mississippian program to maximize cash flow from that asset and now have a portfolio of high-return projects weighted towards oil.

Let me walk through each of these areas outlined on Slide 3. First our balance sheet. We have and will continue to protect this unlevered balance sheet liquidity and maintain a moderate level of outspend. Let's review what we have done here. Our cash is currently around $120 million, that's higher than our cash at the end of the third quarter, even taking into account the $48 million acquisition in early February.

We accomplished this by aggressively managing our cost and reducing CapEx, coupled with some strengthening in oil prices. We refinanced our credit facility and converted all of our mandatorily convertible debt greatly simplifying the capital structure. Combination of this brings our liquidity to over $525 million.

For CapEx we will be guiding to between $210 million and $220 million. I'll talk more about CapEx in a few minutes, but note that our CapEx guidance includes another 20% service cost inflation to come this year. This will result in a small outspend of approximately $60 million to $70 million using current strip prices and the midpoint of guidance. Going forward, look for us to maintain a moderate level of CapEx outspend and retain our strong balance sheet.

Next, some thoughts on the Mississippi Lime, where we have continued our high-graded harvest of this large mature and cash flowing asset. Due to great efforts of our talented operating teams, our 2016 program set new records and did exactly what we intended for this asset.

The data on Pages 4, 5 and 6 of the Slide outline many of these accomplishments. Our 2016 Miss program generates a 51% rate of return. This is using actual CapEx, production and realized prices and then strip prices on each well forecast thereafter. Even burning this 2016 program with saltwater disposal, electrical and cost of future [indiscernible] artificial lift changes, that return is still 44%. Our teams continue to innovate with our well designs and several new applications of our multi-lateral wells including our first dual-extended reach lateral, which is two-mile laterals from a single well bore.

Full year D&C cost also hit a new low with an average of $1.7 million per lateral, with the last two laterals in the fourth quarter being our lowest cost ever, only $1.3 million per lateral.

On Page 6 you can see that our EURs are up and importantly, the variability of the program is down significantly, with a current P10 to P90 ratio of only 2. We still have 400,000 acres with almost 75% of that HBP and have a reliable inventory of 300 remaining Miss and Chester locations, with only about 60 of those currently booked-to-spud.

Putting this all together productions, cost, and innovations, the Miss generated 2016 actual cash flow of just over $150 million, that's a gross profit of $200 million less Mississippian CapEx of $47 million.

Turning the Page 7, the Northwest STACK where we have 60,000 net acres is the newest addition to our development program. It's within our existing leasehold and will be a near-term focus where we will be adding a second rig in March. The benefit of our large, over 400,000 acre position in the Mid-Con is that we can uncover additional opportunities and zones, which is exactly what we have been able to do here in the Northwest STACK.

Late in 2014 into 2015, we drove three Osage wells in Northern Garfield County, Oklahoma. This is adjacent to our Miss development in the area, and our thesis here was, we believed this zone had higher oil content and lower water cut. The results of those three initial wells were encouraging and we started refining our geologic model of the play.

Then in 2016, we drove an additional Osage well and two Meramec wells. These wells had excellent results that you can see in our press release with the Medill well, the Major County Meramec well achieving a 30-day IP of 925 barrels of oil equivalent per day, which at the current strip is in excess of 100% rate of return.

On heels of these results, during that 2015 and 2016 timeframe do our land leasing program, we added about 28,000 acres in major Garfield and Woodward counties to support this thesis. We did this at an average cost about $650 per acre.

Finally, in February of this year, we purchased an additional 13,100 acres and some production in Woodward County, Oklahoma for approximately $48 million. You can see some details of the acquisition on Page 8. This acreage was adjacent to our existing Meramec and Osage development Major County, and in very close proximity to strong producing results from several other operators.

On Page 9, we lay out the returns and cost of each of our plays. Based on our data and industry results, we are forecasting a Meramec type curve of between 500,000 and 1,600,000 barrels of oil equivalent for standard lateral and 800,000 to 1 million for extended reach lateral, all with 40 percent oil. This gives us returns in the 25% to 40% range, and these cost and returns do get – do take into account recent service inflation we're experiencing.

Northwest STACK is an example of us expanding our resource base into a higher return, oily resource play that is very complementary to our core competencies and importantly within our existing acreage footprints. I am very excited about this adjacent play, where we've already been drilling and developing for over two years and just completed this complementary bolt-on acquisitions.

Moving on to our Niobrara oil play in the North Park Basin of Colorado, John will give you some very comprehensive details of 2016 wells and program. I am very pleased with the results of this program. In our initial year of development, our first 10 wells are above type curve. We've done a successful extended reach lateral in our first C bench test, which was the second highest IP of our entire 2016 program and confirms the presence of a very productive second bench in the Niobrara. Costs are down to $3.5 million per lateral and going lower. This leaves us with about 1,300 2P locations, only 106 of which are booked as spuds with upsides from additional benches and tighter spacing.

As you look at our results and hear from John and Julian on the call, there are other very notable accomplishments since our emergence in October. Production hit the high end of guidance while spending below are CapEx guidance. If you recall, we started the year estimating $285 million of CapEx. We ended the year spending just over $200 million while achieving the high and of our production goals.

We continue to reduce our cost structure across the board. We took additional steps in the fourth quarter, reducing our headcount and overhead cost, and again lowered our cash G&A to $69 million in 2016, that's down from $114 million in 2015, and we're guiding to it again lower, $63 million in 2017. We will remain focused on reducing our operating costs.

So, why do I think it is important to go over all the details of what our teams have accomplished these last several months? It's because we are just getting started and these accomplishments are covered are tangible examples of how we are driving our business and making real improvements. We will continue to improve our business every quarter and I commit to keeping up this very intense pace of progress.

Turning to our CapEx plans. We're maintaining the strong balance sheet and liquidity that I talked about, we plan to spend between $210 million and $220 million on capital expenditures in 2017. The details of our CapEx are outlined on Page 10.

As I referenced earlier, this D&C CapEx does assume that we have another 20% across the board service cost inflation, that's on top of the approximately 10% cost pressure we have already experienced in the last couple of months. We will keep a close eye on these costs and are making improvements to our programs to offset these increases.

D&C CapEx of approximately $150 million is allocated between the Mid-Continent North Park Basin, with majority going towards the Northwest STACK. We're seeing excellent results from Meramec drilling in this area, both from our wells and those of other respected operators.

And in 2017, we plan to drill a combination of Meramec extended reach and standard laterals in three counties. Also in the Northwest STACK, we will be drilling almost exclusively on unproven sections, and believe this will add significant resource and locations.

I do expect our pure Mississippian drilling in 2017 to be limited. But keep in mind that our Miss and Chester acreage is almost 75% held by production, with about 300 locations.

On the Niobrara, in North Park Basin, in 2017, after we complete our in-process 3D shoot, this summer we will add one rig to drill three long laterals, including testing another Niobrara bench, testing spacing and stepping-up and delineating the play to the Southwest. We're generating good returns from the Niobrara with the cost EUR returns outlined on Page 9. After this 2017 program, we will look towards a full development program in the play. We have a $40 million land budget this year, primarily for Mid-Continent assets, as well as finalizing or 3D shoots in the North Park Basin.

You'll notice infrastructure spending has decreased to $7 million. This is a reduction from $18 million in 2016 and $58 million in 2015, as we've been able to realize much greater efficiencies from our existing infrastructure. This brings total production to 14.4 million barrels of oil equivalent with 4.1 million barrels of oil.

I discussed our production declines before including on our last quarterly call. We will have a logical production decline in 2017, a result of coming off of much higher activity levels in 2014 and 2015. So, to put this in perspective, those two years combined 2014 and 2015, we turn to sales 638 laterals and in 2016 we turned to sales 34.

For 2017 we expect fourth quarter production on a Boe basis to be down 20% from the fourth quarter of 2016, with our drilling focused on the more oily Northwest STACK and Niobrara, our oil production turns in the back half of 2017 and begins to grow in Q4. That Q4 2017 projected production is approximately 3.5 million barrels of oil equivalent with 1.1 million barrels of oil. That's a 31% oil content versus 28% oil in the fourth quarter of 2016.

So, our focus is on cash flow and returns, and not necessarily, a 6 to 1 conversion Boe growth. The focus on resuming oil growth, supports better EBITDA growth and greater cash flow generation.

In summary, we now have a portfolio of opportunities much more weighted towards oil and where we capture the type of efficiency gains, we have concretely demonstrated in the Miss, where we are the lowest cost operator. In the midst, we're executing of high-graded harvest and achieving new records every quarter, and this asset will continue to generate strong cash for.

Value creation in the Northwest STACK and North Park Basin speaks to the diversification, higher oil content and expanded opportunity set, we're now working with, where initial results in both of these plays are exceeding our type curve expectations.

Our capital allocation will continue to be dynamic, as market conditions, opportunity sets and cost change this year, and any outspend will be moderate as compared to our liquidity and cash flow. CapEx will be weighted toward the best risk adjusted return opportunities and places where we can apply our open band competitive advantages and capture real resource value.

I do want to stress that our oil production will begin to grow and will turn the corner in the back half of the year. So with the balance sheet that is completed unlevered and over $525 million in liquidity, our proved PV-10 of $950 million of NYMEX strip combine these with specific opportunity we now have in our asset base including a new 60,000 acre play in the Northwest STACK, and I believe we have a very compelling value creation story.

Now let me turn the call over to John Suter.

John Suter

Alright, thank you, James. I'm pleased to share with you continued strong execution by our SandRidge team. There's building excitement in virtually every aspect of our business.

Let me start with four highlighted items and then we'll zoom into a more detailed view. First let's examine our basic metrics that show production was higher and costs were lower than anticipated. We delivered production at the high end of guidance with oil, NGLs and total equipment production. Our lease operating expenses were lower than guidance at $7.98 per Boe.

Second, we are drilling with good efficiency in the right areas. I'll be highlighting the Hebron 4-18 and Castle wells in North Park Basin that each set records in the play. In the Mid-Continent, we'll focus on the Medill well in Major County that is already one of the top performing Meramec oil wells in the county to-date.

Third, we're showcasing our position in Northwest STACK. This is a well-verified extension of one of the most active plays in the country. It now gives us additional Meramec and Osage opportunities that create even more diversified inventory. Plus, we have added on that acreage – to that acreage footprint, a recent acquisition of a private operator in Woodward County. Finally, we're adding a second rig in March to accelerate the development of all the opportunities just mentioned.

Now, let me tell you what's happening in each asset and provide you with some data so that you can be as excited as I am about our progress.

Let's start with Slide 11. Here you see on the inset map, SandRidge's primary regions. In the North Park, our Niobrara resources is 80% oil component, increases value and provides years of future development opportunities with our 1,300 identified 2P locations.

In our Mid-Continent asset, we hold 420,000 acres including 60,000 in the Northwest STACK with over 1,300 producing wells. Our Mid-Continent drillable targets now include Meramec, Osage, Miss Lime and Chester across our existing acreage that has now expanded into the Northwest STACK.

First, let's review activity in North Park. You'll recall that we acquired 132,000 acres in December 2015. On the map on Slide 12, you'll find our asset located in northern Colorado between the DJ Basin to the east and Sand Wash Basin to the west. Our current net production is 2,500 barrels of oil per day from the 26 wells we operate.

These laterals exhibit a relatively flat initial oil rate at around 400 barrels of oil per day as you can see on Slide 13 in the first several months of production. This is primarily due to the over pressured nature of the Niobrara reservoir. There laterals will free flow for two to three months, at which point artificial lift is installed to further extend the plateau.

Since entering the play, we've drove 11 Niobrara laterals that outperform the type curve and as shown on Slide 14, accomplished several key initiatives that move us further toward development on a larger scale. In the fourth quarter, we completed the Hebron 4-18H, our first Niobrara C bench lateral. It had a 30- day IP of 539 Boe per day, 92% of that oil. This is the second highest 30-day IP per lateral any well we drilled and is a significant milestone since it confirms development potential for multiple benches in the play.

We also accomplished our lowest drilling cycle time to-date in North Park of only eight days, a pretty strong accomplishment for nearly a 12,000-foot well and only our ninth well in the play.

Next, we achieved a record $3.4 million per drilling and completion costs, with our Castle 1-17H 20 extended lateral that in in the D bench. It produced a 30-day IP of 901 Boe per day, 91% oil. This well has been critical to achieving our lowest cost per lateral to-date and paves the way for further cost reductions from successful application of extended lateral technology. Last quarter we reported that our first five laterals had an average 30-day IP of 478 Boe per day consisting of 90% oil.

The next three one-mile laterals, the Mutual 2-8, Mutual 3-8 and Mutual 4-8, tested various frac designs including slickwater. While the 30-day IPs on these three wells were below type curve, averaging 210 Boe per day, the cleanup period has been longer due to the 30% more water pumped on slickwater stimulation job.

These wells are all now responding favorably to artificial lift and we do expect to achieve type curve EURs as flowback water is fully recovered. The Hebron 4-18H and Castle wells returns the original cross-link frac designs and have all been outstanding performers.

Let's look at Slide 15, where the green where the green cumulative production curve illustrates that we further substituted our type curve projections with a combined 11 lateral total that performs 9% above the type curve.

Shifting to our 2017 development program with the completion of our 3D shoot, we will use one rig commencing mid-summer to drill three extended laterals. We plan to perform multiple bench and spacing test, as well as cut a core to evaluate adjacent formations. Furthermore, with the technical achievements accomplished to-date, our operations team has the line of sight to repeatedly achieve laterals under 3.5 million.

On Slide 16, you'll see that North Park wells will generate approximately a 33% IRR at strip price with a $3.4 million per lateral drilling and completion cost. We believe 2017 will be an important year to further gain efficiencies, progress Niobrara bench development strategy and other potential reservoir targets, before beginning full development within this play.

Now let's shift to the Mid-Continent results. With our 2016 Mid-Continent development program, we were able to successfully execute our plans to drill our best locations, focus on multi and extended lateral drilling, and achieve lower drilling and completion costs. We drove 28 laterals with the one-rig program.

Our Mississippian program consisted of 100 percent multi and extended lateral design. As you'll see on Slide 17, our 2016 high-graded harvest of Mississippian locations, provided an IRR of 51% with an average cost of only $1.7 million. Most recently, the Company drilled, two extended reach Miss laterals; the Cherokee 1-2H and Cherokee 2-2H with an impressive drilling and completion cost of $1.3 million per lateral.

The two wells or four laterals produced a collective 30-day IP of 2,226 BOE per day, 49% oil. Also in 2016, we continue development activities in our Northwest STACK play and Garfield and Major counties. The STACK was originally established through industry activity in Oklahoma's Canadian and Kingfisher counties.

The right side of Slide 18 shows that the STACK consisted of two primary targets, the Meramec and Osage. The Meramec containing interbedded shales, sands and carbonates is at depths between 5,800 feet and 12,400 feet. While the Osage on the other hand contains a low-matrix processing, dense limestone and cherts that exist between 5,900 feet and 12,500 feet to vertical depths.

The insert map on Slide 19 illustrates how development is extended north and west, into what is now considered the Northwest STACK. The Osage and Meramec are prospective in both areas, including our 60,000 net acres of which, roughly half is in Major County, another third in Woodward County and the balance is Garfield County, Oklahoma.

Move to Slide 20, you see the company's presence in the Northeast STACK began in Garfield County, with three lateral targeting the lower Osage, roughly between Q3 of 2014 in Q3 2015. The Benkendorf 1-24H and Benkendorf 2-24H and the Henry1-23 produced a combined average 30-day IP of 618 Boe per day, 74% oil.

As James mentioned, these wells had good IPs with relatively high oil cuts, but were under stimulated by roughly 80% compared to our current designs. Believing that a Meramec target would be faster to drill, provide production uplift and access Osage reserves, we offset them with a horizontal well. The Charlene 1-29 was this well and it went to sales in Q2 2016 producing a 30-day IP of 328 Boe per day with 54% oil.

The well proved the development concept worked, even though it was still under stimulated, roughly half of today's practices. We're eager to soon drill a Meramec offset to the Charlene that will take advantage of extended lateral wellbore design and larger stimulations.

After our success in Garfield, we evaluated our acreage holdings in Major County from Meramec and Osage targets, and planned our first development wells.

As indicated on Slide 21, there is substantial industry activity in the Northwest STACK. 13 active rigs, with over 50 laterals producing, that helped to delineate our acreage. Our first floor Osage major county lateral, the Keeton 1-24H went to sales in early Q4 2016 producing a 30-day IP of 540 Boe per day, 46% oil with drilling and completion cost of $4.2 million.

The two reasons why testing the Meramec influenced our next move; one, Meramec could potentially be drilled with extended laterals; two, it has enough thickness in our acreage to support high volume productivity.

The Medill 1-27H, our first Major County lateral targeting the Meramec went to sales in late Q4, producing a 30-day IP of 925 Boe per day, 77% oil for only $3.9 million drilling and completion cost. There are four other strong Meramec competitor wells in the area producing for at least 30-days. We're encouraged by our results and will spend approximately $30 million on additional Northwest STACK leasing and renewals.

Also on Slide 22, you will see the highlighted block of 13,000 contiguous acres that James mentioned and that the Company recently purchased from a private operator. This addition is complementary to our existing assets and we see potential for STAC play with both Meramec and Osage targeting. Although, we're still evaluating well spacing four to eight laterals per section is very common within industry, and we anticipate a similar approach in our lateral placement.

In closing, with the addition of our STACK acquisition and leasing program, we'll be adding a second rig at the end of the first quarter. As James mentioned, we'll see a positive oil growth in Q4 2017 from the impact of our development activities.

I'm excited about the strategy we have discussed today and like to think our team for the contributions over the last year, and look forward to seeing how they'll apply their innovative low cost approach in the Miss Lime to our growing Northwest STACK and North Park assets.

I'll now turn the call over to Julian.

Julian Bott

Thanks John. I'm pleased to have the chance to address where we are from a financial standpoint. The summary is bright as beyond a small building note, we have no outstanding debt whatsoever with $537 million in liquidity. This strong position allows us to develop our portfolio of assets and take advantage of growth opportunities such as the Northwest STACK acquisition, while carefully managing all liquidity and maintaining conservative leverage.

Take a look at Slide 23, it's worth highlighting that we recently entered into a new $600 million revolving credit facility with an initial borrowing base of $425 million. The transaction was very positive for SandRidge as it provided us an extra $50 million of cash, lowered the interest rate, eliminated certain financial covenants and moves us back to a conforming RBL.

Our liquidity is substantially higher than we anticipated, as we achieved higher than projected EBITDA due to commodity price improvement and our careful management of expenses. LOE, G&A and CapEx all came in under budget.

We also realized $22 million from non-core asset sales, and as we noted earlier $50 million of cash was released from escrow by our banks following the refinancing of the old facility. As a result, our cash position today is $120 million, which is higher than at emergence despite funding the $48 million acquisition, when we closed the Northwest STACK.

Following the refinancing, our remaining $264 million of convertible unsecured notes mandatorily converted into equity. This simplified our capital structure such that we now have no net debt and only have our undrawn revolver, a small building note and common stock. Our capital structure is now completely unlevered, clean and demonstrates strong liquidity.

Now, I'll walk through our key financial measures for the year ended 2016 and 2017 guidance. Production for the year was 19.4 million Boe. For 2017, our guidance is 14.0 million to 14.7 million Boe. LOE was $155 million compared to $309 million for the prior year. This $154 million decrease was attributable to a reduction in drilling activity, reduced workover activity and substantial operational cost improvements. On a Boe basis, this represents $7.98 and $10.29 for 2016 and 2015, respectively.

You will see on Slide 24 that we are guiding LOE in the range of $8 to $9 per Boe for 2017. These numbers incorporate an accounting adjustment that I will discuss a little later on.

Adjusted Cash G&A was $3.55 per Boe or $69 million for the year. This represents a substantial reduction from the $114 million in 2015. Consistent with our continuing focus on cost, including proactively reducing corporate headcount by 23% in the fourth quarter of 2016, our guidance for cash G&A is at a run rate of $63 million for 2017.

Our adjusted EBITDA was $238 million for 2016. This is a decrease from 2015 primarily due to lower commodity prices in production, partially offset by reduced LOE and G&A.

CapEx came in at the bottom-end of guidance at $203 million as we scaled back activity in the fourth quarter due to industry conditions and give our team a chance to review well performance in our developing plays.

As John explained, we are currently looking to spend a similar amount in 2017 with guidance in the range of $210 million to $220 million, and thereby managing to a modest cash flow outspend of approximately $60 million to $70 million, such that our liquidity remains very strong and our net leverage stays at zero.

Under the current plan, we do not foresee needing to draw on the revolver in 2017. Beyond our financial results, fresh start accounting now applies since this is the first set of financials we have issued since emergence. As such, there are some accounting items worth point out. First, we previously recorded our gas transportation cost in LOE. In conjunction with fresh start accounting, we have changed our accounting for this and now book gas transportation costs as a deception to revenue. There is of course, no net EBITDA impact from the change, it is a shift from LOE to realize pricing.

Additionally, as a fresh start accounting, we recorded a noncash ceiling test write-down of approximately $319 million at year end. As we described on Pages 54 and 58 of our third quarter 2016 10-Q, this impairment was the result of GAAP, whereby we are required to use strip pricing for our emerging fresh start balance sheet and then impairment test using lower SEC pricing at year-end. Due to the fact that strip pricing at emergence was much higher than SEC pricing at year-end, a ceiling test was almost certain to result.

Turning now to our reserve picture, there is a lot of detail on Slide 25. We ended the year with 164 million Boe of proved reserves having an SEC PV-10 of 438 million. This compares to reserves at strip pricing of 184 million Boe with a PV-10 of 946 million based on our December 30, 2016 NYMEX strip.

Our PDP PV-10 at the same strip is approximately 730 million and oil content grew from 24% to 32%. It's important to understand that 85% of the 95 million Boe performance provisions were primarily driven by changes to our GAAP and NGL reserves. As we discussed during our third quarter call, substantially all the PDP performance revision was from post 2021 gas production assessment in a subgroup of our Mid-Continent Mississippian properties.

Note that our 2016 drilling plan added just over 9 million Boe through additions to both PDP and spud reserves. And all of the Company's estimated proved undeveloped reserves at December 31, 2016 are expected to be developed within the next five years.

Last, I'll talk about commodity prices and hedging. Since the end of the third quarter, we actively put on hedges for both oil and gas in 2017 and 2018. We've done so at average prices of $52.24 per barrel and $3.20 per Mcf for 2017 and have 64% of our liquids and 77% of our gas production hedged for 2017.

As we go forward, look for us to continue to protect cash flow through hedging with a particular focus on the first 12-months and opportunistically extending for up to three years. In summary, our balance sheet is now very clear. We have a fully conforming standard credit facility, no leverage and interactive liquidity.

We are poised to develop our three existing projects and take advantage of growth opportunities.

With that, I'll conclude my remarks. So operator, if I think you can please open it for questions.

Question-and-Answer Session

Operator

[Operator Instruction] Your first question comes from the line of John Aschenbeck with Seaport Global. Your line is open.

John Aschenbeck

Good morning. Thanks for taking my questions and congrats on a nice update. My first question pertains to the implications of 2017 activity ramp. In last night's press release, James and in your prepared remarks just now, you spoke to the potential to begin seeing well growth by the end of 2017, and with an activity ramp during 2017, it seems like you could get some pretty nice momentum heading into 2018. So, I was hoping you could provide a general idea of what oil growth could look like in 2018, ballpark figure if you keep activity levels constant and just maintain two rigs in the Mid-Con and one in the Niobrara. Thanks.

James Bennett

Thanks John. To totally understand the question, probably not ready to give 2018 guidance right now, but I can repeat a couple of the numbers that I said on the call. I think it will give you a reasonable idea of the trajectory. We ended the fourth quarter of 2016 at 28% oil. We'll end the fourth quarter of 2017 at 31%, about 1.1 million barrels fourth quarter 2016 was 1.2 million barrels and our oil product kind of troughed in the third quarter and then it starts to grow in the fourth quarter. So, I can't give you a percentage in 2018 right now. We'll be able to do that later in the year, but you can see the change from fourth quarter to fourth quarter 28% to 31% oil.

John Aschenbeck

Alright. Fair enough, that does help understand the trajectory. It's helpful. And then in the STACK, you know in terms of M&A, what is – what's the remaining opportunity set look like in the Northwest STACK in terms of your ability to continue that acreage right around that 2,000 an acre mark? And then also what's your appetite to add acres there? Are you satisfied with the 60,000 or are you more inclined to build that out?

James Bennett

We've got a $40 million land budget in 2017, think about $9 million of that is for some seismic acquisition and processing, so call it $30 million in change of land. That will predominantly be focused in the Mid-Continent, so our land teams are pretty active looking in the area. We'll certainly look to add acreage in areas and sections where we're drilling and where we like and take advantage of force pooling where we can. There are a number of opportunities in the Northwest STACK. You can look at the permits, there's half a dozen or more private companies there that are pretty active drilling and there is some of the big well-known public guys that are also there. So, I think in our four county areas, we've got about 13 rigs running right now. But there are more opportunities. We like our 60,000 acre position, but we will be opportunistic that position can keep us busy for a while, but if see something, it looks good, it's right in our area of interest and we think is a good risk adjusted return. We might take advantage of that.

John Aschenbeck

Got it. Appreciate that. Then last one from me, so maybe just higher level comments for the basin, and get your thoughts. What was the point of inflection with the Northwest STACK? It seems that has been somewhat ignored by the industry to-date, but potential return profile now was pretty compelling and it seems like you and other operators are accelerating there. So, was just hoping you could provide your thoughts on what's been the primary driver behind increasing capital efficiency improvements, what would that be a new completion technique or something else?

James Bennett

You said it's been ignored, which is true. I don't think it's been publicized as much and as we talked about, we started drilling some Osage wells in late 2014 and into 2015, liked it there, tried a Meramec target and stepped mover to Major and try to lower Osage that we like and then tried out another Meramec, we're drilling long Meramec now, so I think it hasn't been publicized as much as the original stack that people think about, but was 13 operator there, there is a lot of activity. I think a few things have caused it to change or come about, changes in stimulation, design and techniques and long laterals.

We under stimulated those first Osage wells with about 200 pounds per foot, even under stimulated our first Meramec well with I think 575 pounds per foot, so I think modern stimulations have helped. Targeting is a big issue here in this area. The Osage is very thick, 1,300-feet thick, so it's a big difference whether you are at the top, the middle or the bottom of the Osage. I think people have dialed in, they are targeting and in the Meramec, I think the Meramec's a little thicker than people might have imagined particularly as you go west and you can get a 50 foot to the east or 150 foot thick Meramec to the west, so that makes a very nice target for drilling and also you get some Osage contribution. So, I think it's a combination of all that. John, do you have anything to add to that?

John Suter

Yeah. No, I think initially the Osage was kind of the target. It was a big thick interval and that's what enticed a lot of operators to come in and try to hit some good pretty gassy wells over there, but still some compelling rates. Our geological team was evaluating that during 2015 and 2016 as we started formulating our own plans. The Meramec just as I said in my discussion just really became kind of compelling when you started thinking about what you could do to the cost reduction by drilling extended laterals where you can and certainly as you mentioned the thickness, and then after our Meramec well that we drilled, really exciting, you know probably twice what our type curve is at the moment. So, we're at that as well as some of the other Meramec wells where we've seen so far and there is at least another dozen that are about to come online in the next 30 days. So, we're excited and it did get a bit of a slow start, but it's really kind of ramped up an industry interest.

James Bennett

John, also it had a slow start, because think about what's going on in 2015 and 2016, we were all cutting rigs, cutting CapEx, taking rigs offline. So, I think that's why it didn't get maybe as much momentum in the last year or two as it would have been a normal stable commodity price market.

James Bennett

Got it. That makes sense. Good for me. Thank you guys.

James Bennett

Thank you.

Operator

[Operator Instructions] Your next question comes from the line of Amer Tiwana with Cowen & Co. Your line is open.

Amer Tiwana

Good morning. Hi, how are you guys?

James Bennett

Good morning. Thank you.

Amer Tiwana

I have two questions. The first one is just a clarification on the LOE side, you know you gave range of $8 to $9 and I'm just wondering whether that is inclusive of the transportation costs? And secondly from just a year-over-year perspective, it's marginally higher. I know it's been coming down quite drastically. It seems as though maybe it's because of the production you know coming down a little bit, maybe the cost are now spread over a smaller production base as that, is the right way to think about it?

James Bennett

Yes Amer, you are right. So, the LOE guidance, does exclude the transportation cost as Julian mentioned in his prepared remarks, those are now deduct to the revenue, so you have no change to cash flow or EBITDA, but that LOE excludes the transportation, that's more in line with how the peers treat it. It does increase year-over-year and you are exactly right, you know with production down roughly 25%, you do have some fixed cost that you are spreading over lower production base.

The teams have done a good job to reduce LOE, make moves in the field, take more use of our fully automated operation center and other things, less chemical use. We'll continue to drive that down, but it is up year-over-year on a Boe basis.

Amer Tiwana

And just in terms of our exit – 2017 exit rate of production, where do you peg that at this point in time?

James Bennett

So 2014, I'm sorry 2016, we were at 4.3 million barrels of oil equivalent and that was 1.2 million barrels of oil. Q4 of 2014, we estimate 3.5 million barrels of oil equivalent with 1.1 million barrels of oil. So there is your exit rate for – entry rate really into 2017 and exit rate for 2017.

Amer Tiwana

Okay. Understood. And lastly just, a bigger picture question regarding valuation and you know how we should think about it, clearly you know the enterprise is fairly trading at a significant discount to the PV-10 or no matter how – which metric you look at it, you know roughly four times EBITDA. How should we – first question is, why is that the case, because obviously the industry has you know much higher multiples and I don't find many companies trading at a discount. So, perhaps the first question and second you know what's the pathway to narrowing that discount or maybe trading at a premiums, is that because maybe we need to get back into a growth profile, is that the right answer?

James Bennett

It's a very good high level question, something that we think about, our PV-10 at the strip, UN strip is right about 950 million, you know the PDP component of that is around 730 million, so we're trading even at a slight discount to the PDP. I don't think that's rational or warranted. I'm not going to speculate exactly why? It could be a lot of reasons. We've only been out of restructuring for five months, just under five months now. There is not a lot of information out there about us. This is our first year end call, first full set of annual projections, so it could be from a lack of information out there, could be from a small flow. There is all kinds of different pieces around that.

I think we need to do is do what we said we're going to do, which is execute here, show that we can generate good risk adjusted returns, keep generating cash from our Mid-Continent and deploy that into these two asset bases that we went through the Northwest STACK and even the North Park Basin, get a little more oily and show repeatable results. I think in time, the market will come around and recognize that we are performing and that we should not be trading at a discount. I don't know if time means, one month or one year, but I'm confident if we execute, do what we said we're going to do. We'll get rewarded for that in the market. So, yes, I do think it's undervalued now. I can't tell you exactly why we're just controlling the variables we can control here.

Amer Tiwana

Thank you very much.

James Bennett

You are welcome.

Operator

Your next question comes from the line of Patrick Conner with Whitebox. Your line is open.

Patrick Conner

Thanks guys. Just a really quick question regarding just the last Page on 26, just a clarification question, it does note on the PV-10 valuations for December 31, 2015 and 2016 on the standardized, it shows that it included amounts attributable to the non-controlling interest. Does the 946 contain any non-controlling interest?

James Bennett

No. It does not.

Patrick Conner

Okay. That's all I had. Thanks.

James Bennett

You are welcome.

Operator

There are no further questions in the queue at this time. I will turn the call back over the presenters.

James Bennett

Thank you all for joining us. I appreciate this is our first year-end call and we're excited about the opportunities we have here. I'm trying to clearly articulate our strategy of maintain robust balance sheet, the high grade harvest of legacy and large Mid-Continent asset and there's exciting new opportunities we have particularly in this Northwest STACK. Look forward to seeing you on our first quarter call in May. Thank you.

Operator

This concludes today's conference call. You may now disconnect.

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