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Warren Resources, Inc. (NASDAQ:WRES)

Q4 2013 Earnings Conference Call

March 6, 2014 10:00 a.m. ET

Executives

Saema Somalya - Senior Vice President and General Counsel

Philip Epstein - Chairman & CEO

Stewart Skelly - Vice President & CFO

Bob Dowell - VP and General Manager

Analysts

Ray Deacon - Brean Capital

Jack Aydin - KeyBanc Capital Markets

Operator

Good day, ladies and gentlemen, and welcome to the Quarter Four and Full Year 2013 Warren Resources Earnings Conference Call. My name is Su and I will be your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of the conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the call over to Philip Epstein, Chairman and CEO of Warren Resources. Please proceed sir.

Philip Epstein

Okay. Thank you, Su. Good morning everyone. Thank you for joining Warren Resources’ fourth quarter and full year 2013 financial and operating results conference call. Before we get started this morning, I’d like to hand over the call to our new Senior Vice President and General Counsel Saema Somalya for a comment on forward-looking statement. Saema?

Saema Somalya

Good morning. Before we get started this morning, I would like to remind everyone that all statements made during our conference call that are not statements of historical facts constitute forward looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results could vary materially from those contained in the forward looking statements. Factors that could cause actual results to differ materially from those forward looking statements are described in our Forms 10-K and 10-Q, other periodic filing with the SEC and our press releases.

Philip Epstein

Thank you, Saema. Well done. And welcome everyone. With me in Warren’s New York City headquarters is Stewart Skelly, our Vice President and Chief Financial Officer in addition to Saema. Joining us from our Long Beach office is Bob Dowell, Vice President and General Manager of our California and Wyoming business units. Bob will provide updates on our active drilling program and our core oil assets in California and our Wyoming coalbed methane or CBM natural gas drilling program.

I’d like to begin by saying that 2013 was a strong year for Warren in which we achieved record results in revenues, profits and production. And we solidified our platform for future growth. We also streamlined management, uncovered and achieved significant cost savings and better defined Warren’s focus and mission.

In 2013, Warren produced 2.14 million barrels of oil equivalent. That’s an all-time high for the company and a 6% increase over 2012. Revenues increased 6% over 2012 to $128.8 million despite lower average oil prices. Net income increased a very strong 96% year-over-year to $30.4 million. And EBITDA increased 19% from 2012 to $78.2 million. And our gas reserves increased over 100%.

Based on these results and a thorough scoping of our drilling inventory, Warren has budgeted $116 million of capital expenditures for 2014. That’s a 60% increase over 2013.

Before we jump into more specifics, I'd like to share a few -- with you a few observations. When I was appointed Chairman and CEO in December 2012, I recognized in Warren a company with good assets, good cash flow and a strong balance sheet. In my opinion, Warren was undervalued and underappreciated in the market, which in part was what attracted me to this opportunity.

At that time we used a phrase ‘65 times 3’ to explain the upside of Warren to investors. Warren was 65% enterprise value to PV-10 of proved reserves, 65% PDP and PDNP and 65% oil by reserves. All these signs of a strong asset base and hidden value. Our clear goal in 2013 was to understand our proved, probable and possible resource base, to operate it efficiently and articulate the upside of our assets in operations to investors. Our initial goal is to trade at or above PV-10 of proved reserves. This is a distinction that the better more “exciting” E&P companies have earned, those who demonstrate value beyond proved reserves.

However exciting in Warren’s case doesn't mean a step into virgin shale plays. We focus on what I would call sophisticated plumbing. We leverage our skill sets to exploit and rejuvenate known resources. We are very good at geologic and rate reservoir data mining and the application of state-of-the-art engineering practices. Our message is you see what you get but our mission is clearly to increase what investors can see by expanding our asset base and to see better by stronger communication.

Today, Warren has over 85% enterprise value to PV-10 of proved reserves, 64% PDP, PDNP, and now 48% oil by reserves. Definitely a move in the right direction. And our stock price has increased approximately 80% since December 2012.

Equally important, we made significant progress in our efforts to better utilize our human capital. Internal management has effectively stepped up into new roles and assumed more responsibility. In addition, we were able to attract and add talented new personnel, a good sign in a competitive marketplace, who bring to us technical and acquisition expertise and new perspectives to Warren. The management talent, high energy level and excitement of the company are all high and we are looking forward to an even stronger 2014.

As Bob Dowell will discuss in more detail, our operations team has done an outstanding job in 2013 assuming operatorship of our CBM assets in Wyoming and starting development of our 2013 Leroy Pine acquisition in Santa Barbara County, all the while continuing to optimize and expand our core crown jewel Wilmington oilfield. I'd like to thank our operations and technical staff as well as all of Warren's employees for their all-out efforts this year to achieve outstanding results for our shareholders and position the company for the next phase of its growth.

In a minute, Stewart and Bob will elaborate on 2013 results. But first, I’d like to address a few highlights. On the gas side, in May of 2013, Warren assumed full operatorship from Anadarko over our 86,000 net acre coalbed methane natural gas project in the Washakie basin in South Wyoming.

During the year, Warren’s geology and reservoir engineering teams dug in and analyzed over 200 historical logs and identified approximately 175 additional drilling locations and 400 possible locations on our Spyglass Hill Mega unit, representing a potential gas resource base in our opinion of over 350 bps and as such a large unbooked upside for Warren.

In the Anadarko transaction, we acquired infrastructure assets in a 59 mile pipeline which delivers our gas to interstate markets. Ownership of these assets lowers our LOE by about $0.70 per Mcf and significantly increases our profit margins. On the back of these cost savings in our technical analysis, we successfully executed a 27 well drilling program.

Production volumes from our initial 25 completions continued to increase and dewater at a faster pace than expected. Based on the 2013 well performance and strong economics in the field, we budgeted $39 million of CapEx in 2014 to drill 48 gross CBM wells and six water injection wells.

Production rates for CBM wells inclined and reached peak production in about 1 to 3 years. So we expect the full production impact of this program in 2015 and beyond, despite what might be viewed as delayed gratification from these long-lived gas assets and cash returns to the program should be strong at $4 gas prices.

In California, production volumes in the beginning of ‘13 were impacted by reduction in activity at the end of 2012 as the company changed leadership. However with operations teams’ hard work and contribution from new floods in 2013, oil volumes were held flat overall in 2013 and are expected to increase in 2014. Without a doubt, the Wilmington field is an exceptional oil asset and Warren has identified 150 producing locations in the Wilmington field of which 68 are in the proved category. This represents a 6.5 year drilling inventory.

In 2014, we expect new floods in the Wilmington field and development activity in our newly added Leroy Pine to drive strong year-over-year oil production growth of which Bob Dowell will discuss in more detail.

A particular note is the strong response rate in the Ranger formation of our North Wilmington unit or NWU property. Once the water floods are culled [ph], rates increased steadily and held relatively constant, again somewhat delayed gratification but certainly excellent results. In NWU we have 19 proved Ranger locations and 4 proved tar locations with the potential to identify additional tar locations in the NWU as we develop the formation.

We intend to drill six producers and five injectors in our NWU Satellite 7 facility with 2014 budgeted CapEx of $24 million. We’re commencing construction of Satellite 8 for NWU in 2015 and beyond with a total of 37 locations which will accommodate a planned 20 producers and 17 injectors.

In 2014, our Wilmington Townlot Unit or WTU, we are budgeting for 17 producers and five injectors with the total CapEx of $39 million. A particular note – we’re commencing the drilling of the deeper Ford formation, which we’re very excited about and which is highly prospective reservoir which has not yet been flooded. Warren filled one vertical Ford pilot well in 2011 with encouraging results. In fact, the initial Ford pilot well was also drilled and completed in what's called the 237 formation, which shows promise for additional future development based on log data. We intend to drill 8 Ford producers in 2014 and 2 injectors. Bob will give you a little color on our initial wells but if successful, this Ford program sets up an additional 14 currently identified Ford locations.

Leroy Pine was acquired in September of 2013 and it represents Warren’s first step-out acquisition. Leroy Pine is a conventional Monterey oil play in California Santa Maria basin located in Santa Barbara County. Drilling of the first three wells commenced in October and we anticipated permitting and construction of temporary production facilities by April of ‘14 with production soon thereafter. We plan to drill 12 producers and 2 water disposal wells in Leroy Pine in 2014 followed by 4 producers in 2015.

Warren operates the Leroy Pine project and holds 62.5% working interest. Our total net investment in Leroy Pine is $21 million with $14.5 million allocated for 2014.

Warren’s 2013 year-end estimate of reserves and future revenues was prepared by our independent engineering firm Netherland, Sewell & Associates. Netherland Sewell estimates the PV-10 of Warren’s proved reserves at $504 million, a slight increase over 2012. And this reserve estimate reflects oil prices of $97 per barrel, which is down $7.5 from 2012 as well as gas prices of $3.43 per MCF, up $0.90 from the prior year but still significantly below current prices.

A particular note is our Wyoming natural gas reserves which increased to 103 Bcf from 49 Bcf at year end 2012 due to our successful 27 well 2013 drilling program and commodity price appreciation as well as a better understanding of what we call the refrac potential embedded in the PDNP category. Bob will provide details of our CBM completion methods which we believe will significantly improve performance of our wells.

We believe that the success we saw in 2013 is really just the beginning as we plan to continue to build on our operational results and execution. In our press release this morning, we released 2014 guidance projecting total year-over-year production growth of between 8.5% to 17% and a capital expenditure budget of approximately $116 million. That’s our largest in five years.

In 2014, we also plan to continue our efforts to find opportunities for external growth and use our balance sheet to establish a new core area or as we say a third leg to the stool. As indicated in our previous conference calls, Warren bid on two large acquisitions in 2013 which we did not win but establish an effective M&A process of originating, engineering and financially analyzing transformative acquisition candidates. Both acquisitions were in excess of $300 million of total consideration. Both were conventional, one oil and one gas. We continue to scout for comparable acquisitions.

In scoping acquisition opportunities, we’ve emphasized to date prospects where Warren can gain a competitive advantage by leveraging off of our skill sets. Our emphasis has been on conventional reservoirs with exploitation potential or what we call rejuvenation projects, and an aspect of exploration upside. To date we focus on California and the Rockies where the regulatory environment in our experience effectively navigating the permitting process provides us, we believe, with the competitive advantage.

However as we bring on corporate development and technical personnel and our skill sets evolve, we will look at other basins and asset classes. Warren is well-positioned from a balance sheet and cash flow perspective to execute a significant transaction and we’re confident now that the skills and team we have in place will allow us to add significant value to a number of the assets on the market. I hope to have more to say on these efforts in the coming months.

Through the continued improvement in articulation of the growth potential inherent in Warren’s current assets and by bringing our expertise to bear on new assets, we hope to continue to generate strong returns for shareholders. I am very excited about our opportunities for this coming year.

With that, I'll turn the call over to Stewart Skelly, our Chief Financial Officer, to provide greater detail on our financial results and 2014 guidance. Stewart?

Stewart Skelly

Thanks, Philip. As Philip mentioned, we had a very strong 2013 with record production, revenue, earnings, cash flows and EBITDA. And we’re excited to carry that positive momentum into 2014 and beyond. We also began to realize significant benefits from our efforts to optimize current operations and also enhance our financial management practices, the impact of which can be seen in our reduced operating expenses in 2013, which I will touch on later.

Additionally during the year we conducted an internal evaluation of post production costs and taxes chargeable to royalty owners in our NWU assets. This evaluation resulted in a $5.3 million gain in the fourth quarter of 2013 and will also provide an ongoing benefit in 2014 and beyond by lowering our lease operating expenses in WTU field. We also moved the sales [point] [ph] where we sell our Atlantic Rim natural gas in Wyoming to be at the beginning of a 59 [mile] [ph] pipeline which resulted in us being able to charge a transportation fee and also recognize revenue on our midstream assets during the fourth quarter of 2013.

This morning we released our financial and operating results for the fourth quarter and full year 2013 and in a separate release we detailed our 2013 production volumes, year-end proved reserves and 2014 capital expenditure budget. I'm excited to announce that our 2014 capital expenditure budget of $116 million with $95 million allocated to drilling, represents the most aggressive development program in over five years. With the success we have had to date with our 2013 drilling program, I feel confident that the growth potential which will result from this year’s development program is looking very good.

Our cash flow from operations continues to be strong and in 2013 we completely funded our CapEx plans with cash flows from operation. Also during the fourth quarter we generated cash flow from operations of $21.1 million and we currently have $70.5 million available to us on our senior credit facility. So we continue to be in an extremely strong liquidity position.

Today we reported net income of $3.7 million for the quarter or $0.05 per diluted share, and adjusted net income of $7.9 million which excludes non-realized mark-to-mark losses on derivatives of $3.5 million and also other nonrecurring G&A expenses of approximately $700,000.

Total production for the quarter was 551,000 barrels of oil equivalent, or approximately 600,000 barrels of oil equivalent per day. We produced 292,000 net barrels of oil in the fourth quarter which was an increase compared to the 273,000 net barrels we produced in the fourth quarter of 2012. Additionally natural gas production primarily from our Atlantic Rim projects and Wyoming was $1.6 billion cubic feet during the fourth quarter compared to 1.8 billion cubic feet in the fourth quarter of 2012.

The average realized oil price for the fourth quarter of 2013 $92 per barrel compared to $94 per barrel in the fourth quarter of the prior year, and our average realized price for natural gas in the fourth quarter of 2013 was $3.04 compared to $3.33 per Mcf in the fourth quarter of 2012.

Also during the fourth quarter, we recorded a net loss from derivative of $4 million of which $3.5 million represented unrealized losses from future derivatives and approximately $500,000 represents realized losses from current derivatives. In order to protect the company against a decline in oil prices, the company owns Brent swaps for approximately 1324 barrels of oil per day with a weighted-average strike price of $103 a barrel for calendar year 2014. The company also owns NYMEX natural gas swaps of 12 million cubic feet of gas per day at a weighted-average strike price of $4 for calendar 2014, and NYMEX natural gas swaps of 3 million cubic feet of gas per day at $4.18 for calendar year 2015.

During the fourth quarter total revenues increased 700,000 to $32.6 million. Primary this increase reflects the additional transportation revenue which resulted from a change in the field find [ph] of our Atlantic Rim, gas Wyoming as I previously mentioned.

Total operating expenses decreased 13% to $24.2 million for the fourth quarter of 2013. These operating expenses decreased 900,000 during the quarter to $9.4 million with reflected less remediation work in California and ongoing lower lease operating expenses resulting from the adjustments of post production charges and royalty owners in the WTU.

Depletion, depreciation and amortization expense for the fourth quarter also decreased 17% to $10.4 million compared to the prior period. DD&A was $19 per barrel of oil equivalent during the fourth quarter of 2013 compared to $22 per barrel of oil equivalent during the fourth quarter of 2012. This decrease in DD&A resulted from an increase in proved reserves at the year-end which led to a decrease in the overall depletion rate of 2013.

G&A expense also decreased 18% to $4 million from $4.9 million in the fourth quarter of 2012. This decrease primarily reflects lower salary and severance expense in 2013 as several senior executives departed the company in the latter end of 2012.

Interest expense decreased 11% to 761,000 during the quarter due to lower borrowings under our credit facility in 2013 compared to 2012. For the full-year 2013 we reported net income of $30.4 million or $0.42 per diluted share, an adjusted net income of $34.1 million which excludes unrealized mark to mark losses on derivatives of $2.1 million, another nonrecurring G&A expenses which amounted to $1.7 million.

Additionally during the year we generated $79.4 million of cash flow from operations. Our total oil and gas production was 2.1 million barrels of oil equivalent for the year 55870 [ph] barrels of oil equivalent per day. The average realized oil price for 2013 was $97 per barrel compared with $96 per barrel during 2012 and the average realized gas price for 2013 was $3.41 per Mcf, an increase compared to the $2.78 per Mcf during 2012.

A result of increased production and commodity pricing, 2014 total oil and gas revenues fell 5% to $127.9 million compared to 2012. Total operating expenses decreased, that’s over 3% to 97.3 million during 2013 compared to the prior year. This decrease resulted from both lower DD&A and G&A expenses. DD&A was $21 per barrel during 2013 compared to $23 per barrel of oil equivalent during 2012. And this decrease on a per barrel basis resulted from the increase in proved reserves at year-end which resulted in a decrease in the overall depletion rate for 2013.

Additionally G&A expense was $4.5 million less in 2013 compared to 2012, primarily due to severance packages for the former CEO and certain senior executives being recorded in the latter end of 2012.

Our 2014 drilling and facilities capital expenditure budget is $116 million, $77 million related to our California oilfields and $49 million related to our Wyoming natural gas field. As the operator of our assets in both California and Wyoming we have the ability to modify our capital expenditure budget as commodity and financial markets.

We reported first quarter and full-year 2014 production guidance in a press release disseminated this morning.

Now let me turn the call over to Bob who will provide you with a brief operational update. Bob?

Bob Dowell

Thank you, Stewart. Now I would like to update Warren’s operational details. I would like to start with the operational results in California. In 2013, Warren drilled the a total of 26 new wells and re-drilled one additional well. These new wells consisted of 16 new wells and 1 re-drilled well at the WTU, 7 new wells at the NWU, and 3 new wells at the recently acquired Leroy Pine project in the Santa Maria Valley oilfield.

At the WTU, the 16 new well program that commenced on March 1, 2013 and was completed on October 22, 2013 consisted of drilling and completing 8 producer wells and one injector well in the Tar formation, 3 producer wells and 2 injector wells in the Ranger formation and 2 producer wells in the Upper Terminal formation.

In addition, we re-drilled and – we re-drilled the completion interval in WTU number 2156 which was a Ranger producer well originally drilled in 2011. Capital expenditures in 2013 at the WTU were $26.9 million for drilling related costs and $3.5 million for facility costs.

In spite of commencing the 2013 WTU drilling campaign in the month of March and was 4 [ph] less produced wells drilled in 2013, Warren was successful in exiting the 2013 year at the WTU with a production rate nearly 200 barrels of oil per day or BOPD higher than the 2012 exit rate. A significant contributor to this result at the WTU was the delayed gratification factor Philip mentioned earlier.

The two new Ranger injectors drilled and the one conversion of a Ranger injector in 2013 has had a significant impact on nearby Ranger producing wells. As the gross fluid rates have increased in the nearby producer wells from this added injection support, so too has the oil production increased. More specifically we have observed a 150 barrel of oil per day, incremental production rate increased from 4 nearby prison producer wells as a result of this added injection support.

Additionally the added injection support has reduced the exiting – or the existing production decline rates in these nearby producing wells and in several instances we have observed an increase in production rates. The 2014 capital expenditure program approved for the WTU was $38.7 million which consists of $30.8 million for new well drilling and rig related costs and $7.9 million for facility costs.

Plan for our 2014 drilling campaign at the WTU are 22 new wells consisting of 17 producer wells and 5 injector wells. Highlighting the 2014 drilling campaign will be the 8 producer and 2 injector well development program in the Ford formation. This formation was drilled and adjusted successfully in 2011 at the WTU. These Ford wells are typical vertical producers completed with slide aligners over 600 to 800 feet of producing interval.

Projected production rates include a 50 barrel of oil per day initial or IP rate with typical declines in the first year followed by an increase in year two from the injection support, again followed by typical declines in the subsequent years.

Project economics for the 2014 Ford program reflect a capital investment of $10.5 million and based on assumed net estimated ultimate recoveries or EURs of 576,000 barrels we are targeting an internal rate of return or IRR of 70% based on $85 California Midway Sunset or CMS pricing.

Warren commenced its 2014 drilling program at the WTU on February 16 and has already drilled and completed its first Ford well, the WTU 2150. This producer was placed on production February 27 and over the past three days has average production rates exceeding the anticipated production rates. In 2013, Warren continued to work with the South Coast Air Quality Management District or AQMD to pursue gas sales as the preferred method of disposing of excess gas produced at the WTU.

Warren’s new supplemental CEQA assessment is near approval by the AQMD and discussions are underway on the final permit conditions for the equipment to be installed. Approval from the AQMD is anticipated sometime in the second quarter of 2014 barring any unforeseen delays.

On April 7, 2013 development of the NWU was recommenced for the first time since 2008. A total of 7 new wells were drilled and completed which consisted of 5 producer and 2 injector wells in the Ranger formation. The 7 well program was completed on August 10, 2013.

Capital expenditures in 2013 at the end of NWU were $14.1 million for drilling costs and $2.8 million for facility related costs. As a result of the 2013 drilling program the year end exit production rate at the NWU was 130 barrels of oil per day higher than the 2012 exit rate. Like the WTU, the NWU has similarly benefited from the delayed gratification factor in 2013. The two new injector wells drilled at the NWU were drilled after the producer wells. Therefore we had no injection support for nearly 5 months. Once injection support was obtained in August, gross fluid rates have steadily increased along with the oil production from the five new producer wells. The added injection support has reduced the existing production decline rates in these wells and in several instances an increase in the production rates has been observed.

The 2014 capital expenditure program approved for the NWU is $24 million which consists of $19.3 million for new well drilling and $4.8 million for facility costs. Our planned 2014 drilling campaign at the NWU consists of 11 new wells comprised of 6 producer wells and 5 injector wells. Commencement of the 2014 NWU drilling program is anticipated in late March 2014.

The addition of the five new injection wells at the NWU in 2014 will not only benefit the planned six new producers that will also provide injection support to wells drilled in 2008 and 2013. Project economics for the 2014 NWU Ranger program reflect a capital investment of $19.3 million and based on assumed net EURs of 775,000 barrels, we are targeting an internal rate of return of 35% based on $85 CMS pricing.

Construction of a second drill site in the NWU is also planned to begin in 2014. Completion of this drill site will allow Warren to continue its successful drilling [ph] in the western half of the NWU. We plan on drilling a total of 37 wells consisting of 20 producer and 15 injector wells. Drilling from the second drill site is anticipated to begin in early 2013.

Warren commenced the three well phase 1 development on the recently acquired Leroy Pine project in Santa Maria Valley oilfield with the spudding of the first well on October 29, 2013. We completed drilling activities on the third well on December 7, 2013. The three wells were drilled to the Monterey formation and are planned to be completed in the tar [ph] sandstone that is charged by the Monterey shale. Permits for the construction of the temporary facilities were approved this week by the County of Santa Barbara and construction of the temporary facilities is anticipated to begin within the week.

Once the temporary facilities have been constructed, the three wells drilled in 2013 will be completed and placed on production. Production testing of the three wells is anticipated to begin in April 2014. The Leroy we Pine project represents a new avenue for production and reserves growth for Warren in 2014. As a result, Warren is anticipating moving forward with phase two of the development in 2014. This will consist of drilling 12 producer and 2 water disposal wells.

Warren has approved $12.3 million for drilling and completion expenditures and $2 million for facility and other infrastructure costs. The overall project economics for the Leroy Pine project reflect a capital investment of $21.9 million and based on net assumed EURs of 986,100 barrels we are targeting an IRR rate of 30% based on $85 CMS pricing.

Now I’d like to move to our Wyoming operating results. In 2013, Warren’s geology and reservoir engineering teams analyzed over 200 historical logs and identified approximately 175 drilling locations in our Spyglass Hill Unit. Based on this in-depth technical analysis, Warren drilled 27 CBM wells in 2013 and completed and placed on production 25 of those wells utilizing advanced completion technologies. The two wells that were not completed in 2013 require remedial well work prior to commencing completion operations. The remedial well work will commence after August 1, 2014 when BLM stipulations allow Warren access to the well locations.

The 25 wells from our 2013 drilling program continue to de-water and production rates are inclining towards their peak production rates. Encouragingly the vast majority of these wells are dewatering more quickly and production is inclining more rapidly and achieving higher average daily production rates than our projected type curves depicted. This outperformance is not uniform across all of the 2013 wells and production results are still in the early stages. However we’re very encouraged by what we've seen to date.

If the 2013 wells continue to outperform the predicted production rates and we observe similar results from the wells drilled in 2014, we will most likely revise our current CBM well type curve for the Spyglass Hill Unit which should result in a corresponding increase in reserve bookings and a corresponding increase in PV-10 value. In late 2013, Warren recompleted a previously shut-in CBM producer by isolating a portion of the existing perforated intervals and then fold up with a three stage fracture stimulation program similar to the newly drilled 2013 wells. This well had not been previously fracture stimulated and its perforated completion intervals were not optimized in the same manner as our 2013 wells. This well was placed on production in mid-January 2014 and production results have been encouraging to date.

Continued successful performance of this well could lead to recompletion opportunities on up to 60 additional wells in the Spyglass Hill Unit that have been drilled, are currently shut in and have never been fracture stimulated. This would result in moving significant reserves currently booked under the PDNP category to the PDP category.

Based on the success of the 2013 program, Warren plans to drill 48 gross or 39 net CBM wells and six gross or 4.9 net water disposal wells. These operations will begin in May and will be concluded by November 15 in order to satisfy the 2014 and 2015 annual drilling requirements. The 2014 capital expenditure program approved the Spyglass Hill Unit, is $38.9 million which consists of $32.5 million for new well drilling and $6.4 million for facility costs.

In addition to our earnings release this morning, Warren also issued a press release detailing its year-end 2013 proved reserves. In summary, California oil reserves decreased 2% to 16.1 million barrels of oil compared to 16.4 million barrels of oil at year-end 2012. The PV-10 value of our proved oil reserves at year-end 2013 was $418 million. This reflects the results achieved from our 2013 drilling program and a 6.6% reduction in the SEC weighted average oil price in 2013 to $97.33 per barrel of oil compared to $104.27 per barrel of oil in 2012.

Gas reserves for our Wyoming properties increased 107% in 2013 to 106 BCF on $86 million PV-10 value. This increase in our gas reserves was driven by our successful 27 well drilling program in 2014 and a 36.6% increase in the SEC weighted average gas price in 2013 to $3.43 per MCF compared to $2.51 per MCF in 2012.

Thank you for participating today and I would now like to return the call to the operator for any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Ray Deacon of Brean Capital.

Ray Deacon - Brean Capital

I had a question about the CBM comments that Bob made. Are you saying – so the capital that you spent this year will cover your commitments for ‘14 and ‘15 and so there's no issues with lease expiration; is that right?

Philip Epstein

Yes, that’s correct. In order to really get ahead of the curve and be possibly - as you know, Ray, the stipulations out there which prevents us from drilling on BLM land for a good part of the year, we’re pursuing all 48 wells which covers the ‘14 and ’15 program.

Ray Deacon - Brean Capital

And then just a quick one on the Leroy Pine’s project, I guess given that your experience there is shorter than at the WTU, is there a chance of that rate of return could end up being conservative based on better performance or your ability to reduce well costs?

Philip Epstein

Yes, we think it is. What we did there was there is four type curves and there is I think 27 existing wellbores from decades ago, which performed in various categories, we basically selected the two lowest type curves. If we hit one of the better type curves that historically has been demonstrated it should be a lot better. So we think that this is a conservative, realistic approach.

Ray Deacon - Brean Capital

And what is the target zone there?

Philip Epstein

It’s the – I will let Bob get more detail but it’s Monterey Chert, it's not the shale, the Monterey shale is the source rock and the chert, it’s above it and we’re certainly not holding ourselves out to be Monterey shale players, this is a conventional play. We are drilling off of a pad, so we drill horizontally and then drop down vertically. Bob, do you want to give a little more color on that?

Bob Dowell

Sure. Sure Ray. Yes, we’re drilling into the Monterey formation and it's a pretty thick formation. And at the upper part where a lot of the folding is taking place it’s more of a chert, it’s not the true shale that you would think of. So it has a lot of various fractures and thereby that's where a lot of the production has historically come from. And we’re basically going back in and targeting parts of the reservoir that weren’t developed, that still we believe have a lot of remaining oil potential and you’re basically perforating and allowing the oil flow in via that way, there is no fracture stimulation or gas work involved in this.

Operator

(Operator Instructions) The next question comes from the line of Jack Aydin of KeyBanc Capital Markets.

Jack Aydin - KeyBanc Capital Markets

Could you -- I mean in the past you guys used to talk about the average daily production from those tar wells, Ranger wells, can you in a way update us on those, what do you see in the initial rate and where they typically stabilize?

Bob Dowell

Yeah, really nothing, in the third quarter we talked about the production rates and so last year we drilled 8 tar wells, a significant portion of those were into the newer development areas of the tar formation, our D2 and D3 zones. And those wells had initial 30 day rates of about anywhere from 80 to 90 barrels of oil per day. Those zones being thinner by nature have declined and settled out into about 40 or 50 barrel of oil per range day and what we're doing is because they are thin and have never had injection support, one of the wells we’re going to drill in 2014 is an injector that will supply that pressure support to those wells, we’re hoping for a bolstering of production in those wells.

And this is at the WTU by the way. We also drilled some Ranger wells and those wells IP-ed in about the 50 barrel of oil per range and we are following our typical decline. However as I mentioned in my script, the added injection support has kind of turned those declines around and we’ve actually seen an increase in those wells, so we’re there making over 65 barrels of oil per day at present. So that's a very, very -- the delayed gratification factor that the injection supports, it’s pretty simple math. If you can increase the gross fluids into the wellbores, the oil cuts remaining the same, you’re going to achieve more net oil. So we are in the area of about 65 barrels of oil per day in the Ranger wells that we drilled last year.

The two Upper Terminal wells that we drilled, those typically -- those average IP rates of about 38 barrels of oil per day but in both those wells we've had issues with the completion that was utilized -- we used the standalone liner solution that we've had some problems with sand entering in prematurely. So we are going to go in in 2014 and look at some remedial work to either install a inner liner to prevent the sand from coming in, or we will come up with some other remedial action. So those wells, we’re not quite sure where we’re at, they are both shut-in at present at the WTU but we do have workovers planned to bring those back up. The targeted kind of IP rate for those is about 60 barrels of oil per day and we are hopeful to still achieve that once the remediation processes are complete.

At the NWU, those wells that we drilled there came on again about 56 barrels of oil per day on the five producer wells but as I also described we’ve seen those production rates incline since they were placed on production in early last year or mid last year as a result of those added injectors. And those wells are all currently in the 65 plus barrel of oil per day range at present.

Jack Aydin - KeyBanc Capital Markets

And what is your philosophy in a sense when you look at your cash flow and you look at your budget and in a way, what I am trying to say, how long do you want to spend way in excess of your cash flow, could you frame it a little bit to us?

Philip Epstein

Well, I think what my philosophy is is that we really dug in and scoped our inventory and done a tremendous amount of analysis on the programs we’re going to drill and what the economics are. And on the basis of that we greenlighted projects in the Wilmington and Leroy Pine and in our Atlantic Rim project, all of which make good returns. So for a company that has in the past couple years spent CapEx within cash flow, we felt that it was -- given our technical efforts we think it's a good idea to start spending above cash flow. We have $165 million credit facility, we’re 70 million drawn .We think we can use that credit facility effectively to basically arbitrage a 2.5% interest rate to the IRRs that we expect to see in both our oil and our gas assets. So that’s what -- we feel that by drilling in excess of cash flow that will result in greater reserves, it will result in a greater low-cost senior credit facility and will just perpetuate itself. And so, Jack, I feel pretty confident of the team that’s in place. I feel very confident we’ve got some really good people, very talented people. We are hiring more geologists, we’re hiring more reservoir engineers, we’re hiring more production engineers. It's all lining up to be an effective and prudent investments with debt.

So and again I am not a believer in using debt for exploration but we've got assets which you can apply prudently debt too. So I am pretty excited about using that credit line.

Jack Aydin - KeyBanc Capital Markets

My last question for you is I know you are looking at acquisition and you missed two of them. Could you tell us, if there is a lot in the market, do you see a lot of project or lots of deals that you are reviewing, in a sense an update in that type of thinking?

Philip Epstein

Sure. Yes, we are seeing a lot and we've got some irons in the fire right now in terms of analysis. I think we're going to see some pretty – good things happening in that area. Again the 2013 was an interesting year for the company because we were able to establish good production rates, grow our current assets and really in a sense we almost made an acquisition in my mind with the CBM asset in Wyoming when we took over from Anadarko. But then we increased our reserves there not just by gas prices but by really getting a thorough understanding of what we had, our archaeology team did a thorough analysis and then the operating team came on board. So we kind of built into the organization a very high level of technical and operating capability and now we’re transitioning or we’re using that in a directed way to looking at different opportunities for us. I feel pretty confident that when we put in our bids, we know what we're doing and we’ve got a couple of areas that we’re focused on. Again the Rockies in California, are areas that we feel very confident about.

But as we bring on more talents, we're also going to be looking at other areas. So I think the hallmark of what we look for is -- we don't want to jump into highly competitive areas. We’re not going to be a Permian player. But we are going to look where the hydrocarbons are already known and we’re going to try to buy, if it’s big package, a package with some PDP, so we can utilize that in the acquisition and accrete more value to the common stock.

Operator

You next question comes from the line of Ray Deacon from Brean Capital.

Ray Deacon - Brean Capital

I just had a follow-up regarding one of your peers commented that Hydro generation is going to be down significantly in the West year-over-year and thought, there could be as much as a Bcf a day of incremental demand. And I was just wondering gas prices look very strong currently, sort of what your outlook is for the CBM project and potential capital in the next couple of years, should we continue to see the strength?

Philip Epstein

That's a good question because we're seeing -- frankly we like the Rockies and the CBM assets in particular, and we're seeing what historically has been discount to NYMEX, first we sell at big pricing. But in the last month we were seeing premiums to NYMEX numerous days. We kind of benefited because in certain days, the cold weather froze off producers and we didn’t suffer as much as others and we were able to see some extremely strong days out there, sometimes reaching $25 an MCF. So we like the Western gas assets. The pipelines have come in and so our hedge strategies go 50%, that’s our target. The gas futures are pretty robust. We haven't put on more than 3 million a day for 2015 yet. We got that at $4.17 but we're pretty optimistic about the West. And that's what – and we like the gas assets.

Operator

Thank you for your questions ladies and gentlemen. I would now like to turn the call over to management for closing remarks.

Philip Epstein

Okay. Thank you, Su and thank you everybody for listening in today. We tried to give a pretty clearer report this time. We accomplished the whole lot. The team has really come together. Everybody is working all out. I think that we’re in a great position to take Warren to the next level. Our stock price is performing really, really well and we appreciate all the investor interest. So we hope to be delivering further good news to you in the next quarterly report and hopefully we will be looking at some M&A activity which could further enhance our asset base. So thank you all and have a great day.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a very good day.

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