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Reeling In Small-Cap Alpha

Summary Stocks of small companies have higher incidences of price volatility and mispricing, increasing opportunities for investors to earn excess returns. Implementing outperforming strategies, such as value or momentum, in the small-cap universe amplifies their alpha-generating potential. High trading costs of small-cap stocks disadvantages passive implementation when compared to skilled active management. Although we live at the edge of the Pacific Ocean, our weekend adventures often take us inland to enjoy the lakes and streams of California and her neighboring states. A favorite pastime is fresh-water fishing. For most, the lure of fishing is a combination of serene beauty, contemplative quiet, and the satisfaction of reeling in as many big fish as possible. We admit that the first two attractions are very appealing in their restorative powers, particularly to office-weary asset managers, but we can’t help being most inspired by the basic challenge of catching a lot of big fish. The folklore claims 10% of fishermen catch 90% of the fish. What do the top 10% know that the others don’t? Investors’ search for alpha is not dissimilar to the strategies of skilled and experienced fishermen. First, the skilled know the right location. They use multiple lines and hooks or lures to increase their opportunities. And they attract greater numbers of fish by chumming – adding scent or bait to the water. In the world of asset management, we can think of risk and mispricing as the chum that attracts alpha. Just as all fishing locations are not equal – contrast the teeming Lake Tahoe with the perishing Salton Sea – not all segments of the equity market are equal in the opportunities they present for finding alpha. Small-Cap Alpha: Abundant, but Unreliable Lake Tahoe is well known for both its abundance and diversity of fish. The academic literature has made a similar case for small stocks, often believed to be a deep pool into which an investor can cast her net and pull out a weighty haul of alpha. Stocks of small companies vary significantly in price volatility, are more prone to defaults, and have high trading costs. In combination, these characteristics create an unpredictable risk distribution for small-cap stocks, and the same traits contribute to their frequently being mispriced. In addition, many known anomalies, or risk factors, have significantly higher return dispersion among small companies, creating numerous opportunities for alpha production. Our research shows, however, that small stocks are not a dependable source of standalone premium. Granted, the small-cap universe is plentiful – there are thousands more small companies than large companies – and diverse – the U.S. economy encourages virtually any type of business or strategy an entrepreneur can envision – but these traits alone are insufficient to ensure small caps will unfailingly produce an excess return. Many market participants believe that, just like value stocks outperform growth stocks, and positive momentum stocks outperform negative momentum stocks, small-cap stocks outperform large-cap stocks. In a recent article (Kalesnik and Beck, 2014), we discuss the evidence that supports the size premium. Table A1 in the Appendix lists the main arguments in favor and against small size as a standalone source of premium. In our view, the arguments against are much stronger than the arguments in favor: we judge the evidence that small-cap companies, in general, outperform large-cap companies to be unreliable. Our advice to the equity investor is to examine that small cap you are considering to be sure it has the alpha-producing qualities you seek – if absent, toss that small fish back, and cast your line again. Small caps are not the fish, they are the fishing spot – not the source of alpha, but rather a place where alpha can be found. A Fertile Fishing Spot Even if small companies are not as a group reliably outperforming large companies, small-cap stocks still hold significant promise for investors – they are a fertile fishing spot for alpha. Small caps, like other investment strategies, benefit from two potential sources of outperformance: 1) exposure to sources of risk that are compensated with higher returns, and 2) systematic sources of mispricing that can be exploited. Small stocks come with higher risk than large stocks as measured by credit rating, delisting probability, and volatility. Table 1 reports the distress and volatility characteristics of U.S. stocks by size quintile. The S&P credit rating difference between small-cap stocks (B rated) and large-cap stocks (A+ rated) indicates the higher likelihood (over 200 times) of smaller stocks being delisted, often because of default. Small caps have a delisting rate of 2.38% versus 0.01% for large caps. The higher price volatility of small caps is evident at both portfolio and stock-specific levels. The portfolio composed of the smallest 20% of stocks is about 44% more volatile than the portfolio of the largest 20% of stocks – 20.6% versus 14.3%, respectively. A portfolio, however, masks a lot of stock-specific volatility. A comparison of the median stock volatility of the highest and lowest quintiles is significantly more striking: the median volatility of the smallest stocks (50.5%) is almost 100% more volatile than the median volatility of the largest stocks (25.5%). Also, the dispersion in stock volatility is much greater for small stocks than for large stocks, with a 25th-75th percentile range of 32.1%-76.0% compared to 19.8%-33.2%, respectively. With a much wider dispersion in stock-level risk, investors looking to capitalize on known risk premia should consider doing their fishing in the small-cap side of the pond. Smaller companies, by virtue of their vast numbers, limited market liquidity, and resultant lower investor demand, tend as a category to have very light analyst coverage. Therefore, much less is known by, or available to, the average investor about the fundamental strength of most small companies. Investors struggle to digest this complexity and to translate the information they are able to discern into efficient prices. Greater instances of mispricing are the practical outcome. Such mispricing creates an opportunity for investors to capture excess returns, much as the fisherman’s baited hook entices the next bream that skims by. If mispricing in the small-cap segment of the market is well known, why does the mispricing persist? Why is it not arbitraged away? One likely reason is high trading costs. Table 2 lists the average bid-ask spreads for each of the size quintiles over the period 1988-2014. The bid-ask spread serves as a proxy for trading costs. Clearly, the average spread is much higher for the smallest-cap quintile compared to the largest over both the entire 27-year period and the last 10 years. Large trading costs make potential trades of small-cap stocks less profitable, allowing the mispricing to persist. Just as a lake with heavier vegetation provides a more fertile environment for fish to thrive, we believe the small-cap universe provides fertile ground for finding highly mispriced stocks. In the never-ending debate over whether certain sources of outperformance – such as value and momentum – arise from risk or mispricing, for our purposes, it actually doesn’t matter! Based on the evidence we have just presented, small caps offer a bountiful location to find alpha. Reeling In Alpha As we stated in the previous section, outperformance requires that risk be adequately compensated by return. In seeking excess returns, we can attempt to exploit the higher riskiness and greater probability of mispricing in small-cap stocks by implementing outperforming strategies – such as those that capture the value, momentum, and quality premiums – within the small-cap universe. Value in small caps. In the simplest interpretation, value strategies favor the stocks of companies with high accounting fundamentals-to-price ratios (value stocks) relative to those with low fundamentals-to-price ratios (growth stocks). The high ratio of fundamentals relative to price can signal that the stock is justifiably risky so that the market is willing to purchase the stock only at a reduced price. Alternatively, the high ratio may signal that the stock is actually underpriced for its fundamentals. In either case, historical experience has shown that buying value companies has been a profitable strategy. For value stocks deemed to be cheap because of higher risk, this characteristic should be magnified in the more opaque small-cap universe, and hence, offer investors a higher premium for assuming that risk. For value stocks attributed to mispricing (i.e., fundamentally strong stocks being temporarily priced too low, and vice versa), returns should be higher when the value strategy is executed in small caps because of the greater potential for the mispricing of small companies. In Table 3 , we show the performance of different definitions of value strategies implemented in both large-cap and small-cap stocks from 1967 to 2014. Value stocks, regardless of the definition of value, 1 outperform growth stocks in both large-cap and small-cap market segments. More importantly, the outperformance of value stocks relative to growth stocks is significantly larger for the strategies executed in small-cap stocks. The t-stats of two of the long-short value strategies implemented in small caps are significant at the 1% level, and one is significant at the 5% level. This compares to two of the same strategies implemented in the large-cap universe being significant at the 5% level, and one at the 10% level. Momentum in small caps. The momentum strategy favors stocks that over a recent period have risen steadily in price. Once identified, these stocks typically continue their upward, outperforming trajectory for an additional period of time; momentum can also assume a downward trajectory. Like the value strategy, the momentum strategy’s ability to deliver excess returns has both risk and mispricing explanations. In our view, the most convincing argument is related to risk, that is, market participants initially underreact to earnings surprises (up or down), only to follow up with a buy or sell action when the earnings information is later confirmed. Similar to the argument we made for implementing a value strategy with small-cap stocks, the risk associated with a momentum strategy would also be amplified when implemented with small caps and would generate a higher return premium. If momentum derives its value-add from mispricing, the fact that small caps are potentially more prone to mispricing should make a momentum strategy implemented in small caps even more profitable. In Table 4 , we compare the performance of the recent winners versus losers in the universes of large-cap and small-cap stocks. The gains from momentum are much higher among the small caps. The t-stats of all five momentum strategies implemented in small caps are significant at the 1% level compared to only two of the five strategies being significant at the 10% level when implemented in large caps. Quality in small caps. Quality investing as a standalone strategy has been gaining a lot of attention. Investing in quality companies is intuitively appealing, but what drivers underlie the strategy? Again, the possible explanations are mispricing and risk. Mispricing theory would argue that investors are unable to correctly translate information beyond simple financial metrics into efficient prices, and risk theory would argue that several metrics related to quality are associated with a distinct undiversifiable correlation pattern, which in a multifactor setting may signal that quality stocks are compensated by a risk premium. If either or both of these explanations are true, we would expect a stronger relationship in the universe of small-cap stocks. A quality strategy encompasses a very broad category of possible signals, creating the danger of focusing on a nonrepresentative outlier. To avoid this potential problem, we identify nine broad groups of quality definitions, and within these groups, 35 narrower definitions. Table A2 in the Appendix provides the definitions. We simulate the performance of the 35 quality definitions in both large-cap and small-cap universes. Table 5 provides these results. 2 We find that for large-cap stocks in the aggregate, quality stocks do not have a performance advantage over junk stocks. 3 By contrast, in the small-cap universe, quality stocks outperform junk stocks. The performance advantage as indicated by the t-stat of the long-short quality portfolio is statistically significant at the 1% level for small caps. In the recent article, “Size Matters If You Control Your Junk,” Asness et al. (2015) document that small-cap companies outperform the market if low-quality companies are avoided. We have a minor quibble with the interpretation of trying to rescue the size premium by controlling for junk. Why not “Size Matters If You Control Your Growth” or “Size Matters If You Avoid Losers”? Arguing that size matters if you control for junk, rather than arguing that most anomalies generate better performance – or any performance at all – when implemented in small-cap stocks, is not much different from arguing, for example, that rebalancing is a repackaged value strategy. At the end of the day, however, our empirical findings and those of Asness et al. are similar: quality small-cap stocks can be a good source of excess return. Both Location and Skill Matter The key to a successful day of fishing is location. The same is true of outperforming in the equity market. The investor must find where alpha is located. Small size – along with value and momentum – is generally considered to be a singularly promising location. Our empirical research, however, calls this general wisdom into question. We find that small size alone does not guarantee outperformance. But small size does offer fertile waters in which to find alpha and reel it in. Both sources of outperformance in investment strategies – compensated risk and mispricing – are amplified when implemented in the small-cap universe because small-cap stocks take both characteristics to the extreme; well-known anomalies show much stronger outcomes when implemented among smaller companies. We conclude that exploiting outperforming strategies within the small-cap universe can deliver excess returns. Because small-cap stocks have high trading costs, implementation skill matters – a lot. Passive implementation of investment strategies in the small-cap segment of the market is definitely disadvantaged versus their skilled active implementation. Active managers can hide their trades, position themselves to narrow the bid-ask spread, and minimize turnover. Ultimately, the equity investor will haul in a larger alpha catch by emulating the skilled fisherman: first, identifying a promising location (i.e., small cap stocks), then using multiple lines and hooks (i.e., implementing value, momentum, and quality strategies to exploit the chum of risk and mispricing in each), and lastly, dangling the lure of skilled active management to tease out the smallest trading costs possible. Endnotes The only value strategy that lacks statistical significance in Table 3 is the strategy defined by dividend yield. It comes with significant volatility reduction, a feature, however, that can make the strategy attractive to some investors. The lower volatility of the high dividend yield portfolio increases the volatility of the long-short portfolio used in the statistical test and renders the difference statistically insignificant. Hsu et al. (forthcoming) document that in terms of Sharpe ratios, the value strategy defined as dividend yields provides an economically and statistically significant advantage. We show only the aggregate results in the interest of space We interpret these findings as a lack of robustness for quality as a broad investment category. It does not mean that individual definitions of quality may not have investment merits; further characteristics may be of interest and deserve more detailed study. References Asness, Cliff, Andrea Frazzini, Ronen Israel, Tobias Moskowitz, and Lasse Heje Pederson. 2015. “Size Matters If You Control Your Junk.” Fama-Miller working paper (January). Available at SSRN. Banz, Rolf. 1981. “The Relationship Between Return and Market Value of Common Stocks.” Journal of Financial Economics , vol. 9, no. 1 (March): 3-18. Hsu, Jason, Vitali Kalesnik, Helge Kostka, and Noah Beck. Forthcoming. “Factor Zoology.” Research Affiliates working paper. Kalesnik, Vitali, and Noah Beck. 2014. ” Busting the Myth About Size .” Research Affiliates Simply Stated, December. Sloan, Richard. 1996. “Do Stock Prices Fully Reflect Information in Accruals and Cash Flows About Future Earnings?” The Accounting Review , vol. 71, no. 3 (July): 289-315. The authors wish to thank Chris Brightman, CFA, and Kay Jaitly, CFA, for their substantial contributions to this article. Appendix This article was originally published on researchaffiliates.com by Vitali Kalesnik and Noah Beck . Disclaimer: The statements, views and opinions expressed herein are those of the author and not necessarily those of Research Affiliates, LLC. Any such statements, views or opinions are subject to change without notice. Nothing contained herein is an offer or sale of securities or derivatives and is not investment advice. Any specific reference or link to securities or derivatives on this website are not those of the author.

US Geothermal’s (HTM) CEO Dennis Gilles on Q3 2015 Results – Earnings Call Transcript

US Geothermal Inc. (NYSEMKT: HTM ) Q3 2015 Results Earnings Conference Call November 10, 2015, 01:00 PM ET Executives Dennis Gilles – CEO Kerry Hawkley – CFO Doug Glaspey – President and COO Analysts Jim McIlree – Chardan Capital Markets Peter Rabover – Artko Capital Bryan Lee – Private Management Group Operator Greetings, and welcome to the U.S. Geothermal’s 2015 Third Quarter Earnings Results Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. With no further ado I would like to turn the conference over to our CEO, Dennis Gilles. Thank you Mr. Gilles, you may begin. Dennis Gilles Thank you, Tim and thank you everybody for joining. Today we want to thank you for joining the call and for your continuing interest in U.S. Geothermal. My name as Tim said is Dennis Gilles, and I am the Chief Executive Officer of U.S. Geothermal. And joining me on today’s call is Kerry Hawkley, our Chief Financial Officer and Doug Glaspey, our President and Chief Operating Officer. We’re pleased with our performance as we reached the end of this third quarter of 2015. Our plans continue to outperform industry standards for operational availability and we continue to focus on our next phase of growth. I would now like Kerry Hawkley our CFO to provide you with the summary of our financial results for this first nine months of the year. Kerry? Kerry Hawkley Thank you, Dennis and good morning to our listeners on this call. Before beginning, we would like to remind you that the information provided during this call may contain forward-looking statements relating to current expectation, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the Company’s plans, objectives and expectations for future operations and are based on management’s current estimates and projections of future results or trends. Actual future results may differ materially from those projected as a result of certain risks and uncertainties. During the call, we will present non-GAAP financial measures such as EBITDA, adjusted EBITDA, and adjusted net income. Reconciliation to the most directly comparable GAAP measures and management’s reason for presenting such information is set forth in the press release that was issued last night. Because these measures are not calculated in accordance with U.S. GAAP, it should not be considered in isolation from our financial statements prepared in accordance with GAAP. I will now discuss the financial statements of US Geothermal for the nine months ended September 30, 2015. You will note that the company is now filing our financial statements and MD&A in a condensed format, which should be read in conjunction with our audited financial statements and 10K filings for the year ended December 31, 2014. On our balance sheet as of September 30, 2015, we have total assets of $228.1 million. Our cash and cash equivalents are $11.2 million with our restricted cash and bond reserves up $21.0 million for total cash assets of $32.2 million. Our total liabilities are $97.8 million, our non-controlling interest has been reduced to $44.0 million and our net stockholders equity has increased $86.3 million. On our statement of operations we’re very pleased with our results for the past nine months. Revenues for the first nine months were $21.3 million, up $180,000 from 2014. Our planned production expenses were $12.0 million, up $238,000 over the same period in 2014. Salaries and wages and stock-based compensation cost were down $268,000 from 2014 levels due primarily to cost applicable to our development projects. US Geothermal no longer has a tax valuation allowance as existed in 2014 due to recording a deferred tax asset in December 2014. In 2015 we recognized an income tax expense of $473,000 for GAAP purposes and reduced the deferred tax asset by the same amount. Please note that US Geothermal has no tax liability until the deferred tax asset is fully depleted. Income tax amount represent cash on US Geothermal’s share of net income only. Our net income for the first nine months of 2015 was $1.8 million. If we eliminate the income tax to just a comparable number to the 2014, our adjusted net income would be $2.3 million in 2015 as compared to $1.9 million for the same period last year. Our net income attributable to non-controlling interests is down $637,000 in due to lower revenues at increased payroll and maintenance costs at our Raft River project. Net income attributable to US Geothermal was $781,000 in 2015 compared to $268,000 in 2014. Earnings at our San Emidio plant increased $547,000 net of tax 2015 compared to 2014 due to increased plant revenues and decreased maintenance costs. San Emidio has owned 100% by US Geothermal. For comparison purposes, if we had not recorded the deferred tax asset in December 2014, net income attributable to US Geothermal as adjusted would have been $1.25 million in 2015 compared to $268,000 in 2014. On our statement of cash flow, we began the year with cash and cash equivalents of $13.0 million. Nine months cash generated by operations was $9.1 million. No payments reduced our total debt by $4.0 million. Payments to our non-controlling interests were $3.5 million. Capitalized development cost at the Geysers, San Emidio 2, El Ceibillo and Crescent Valley totaled $4.5 million. Funds released from restrictions and funds raised via option exercises were $1.1 million for the nine months. We ended the quarter with cash and cash equivalents of $11.2 million. On our statement of changes in stockholders equity, we added net income attributable to US Geothermal of $781,000 during the first nine months. Our accumulated deficit net of tax is now $18.5 million. Shares of common stock issued upon exercise of stock options were 155,000 for the first six months another 428,000 shares were issued with a one year restriction. Cash of $3.5 million was distributed to our non-controlling interest and net income of $1.0 million were allocated to the non-controlling interest. Our shares of common stock issued and outstanding at September 30, 2015, totaled 107.6 million shares. We’re very sensitive to the complexity of our disclosure caused by our partnership agreements. The company continues to evaluate opportunities to simply this process. Please see the disclosure on Page 42 of the MD&A regarding the net income attributable to the non-controlling interest and the net income attributable to US Geothermal and its shareholders. For the first six months, you will see that Neal Hot Springs contributed $2.1 million. San Emidio contributed $752,000 and Raft River contributed $125,000 for a total net income attributable to US Geothermal and its shareholders of $3.0 million. From that, exploration activities and corporate overhead cost $2.2 million. All of these figures are net of tax. Costs in this last category includes the company’s cost of existence including being listed on two stock exchanges, legal accounting professional fees, filings with government agencies, stock-based compensation and the cost of evaluating and developing new projects. These costs represent an investment in the future growth of our company, but are 100% US Geothermal cost and reduce the net income attributable to US Geothermal. As we continue to grow the company by adding new income generating projects in the future, this last category should not increase significantly from current levels allowing the net income from any new projects to increase the bottom line almost dollar for dollar. Thank you for your continued interest in US Geothermal. I’ll turn the call back over to Dennis. Dennis Gilles Thanks Gary. Doug Glaspey, our President and Chief Operating Officer is now going to provide you highlights of our operation performance and our development activities for the last nine months. Doug? Doug Glaspey Thank you, Dennis and good day to everybody. We’ll start with operations. Generation during the third quarter from all three plants was 68,371 megawatt hours, compared to 68,987 megawatt hours in the third quarter of 2014. Generation for the first nine months of the year totaled 237,244 megawatt hours, compared to 242,255 megawatt hours during the same period in 2014. Warmer than average temperatures have been experienced through the first three quarters of the year, but they have moderated now in the third quarter and we’re hoping for more normal temperatures in the fourth. For the year, we’re 4 degrees above the 10-year average temperature at all three facilities. At Neal Hot Springs, our generation for the third quarter was 33,498 megawatt hours and for the first nine months of the year was 124,229 megawatt hours. This compares to 128,922 megawatt hours for the first nine months of 2014. The facility averaged 15.4 net megawatts per hour of operation and achieved 98.5% availability for the third quarter. As we previously announced a settlement was reached with Turbine Air Systems under the terms of our equipment supply agreement in five of their key equipment suppliers. The settlement provided a cash payment of the company, which is project company USG Oregon LLC and a commitment from the five suppliers to repair a specific equipment deficiencies and to provide extended warranty for equipment that is repaired or replaced. We did take a 2.5 day maintenance outage during the quarter on Unit 3 and that was to replace the higher pressure feed pump or the new pump and that part of this EFA settlement. At San Emidio generation was 18,924 megawatt hours for the quarter and for the first nine months of the year, it was 59,170 megawatt hours. This compares to 55,149 megawatt hours for the first nine months from 2014. San Emidio averaged 8.7 net megawatt per hour of operation and achieved a 98.9% availability for the quarter. They’re doing a really great job down there. At Raft River generation was 15,950 megawatt hours for the third quarter and for the first nine months of the year generation was 53,845 megawatt hours. This compares to 58,184 megawatt hours for the nine months in 2014/ Raft River averaged 8.7 net megawatt per hour of operation for the quarter and operated at 82.7% availability. During the third quarter, we did take a 12.5 day maintenance outage that was taken in August to replace variance that we’re failing on both servers. That we restarted, it’s operated smoothly and there is no indication of any further issues. Overall we’re pleased with the continued high performance of all three plants so far this year and we expect to finish out 2015 with a strong fourth quarter. On the development front, at our at our WGP Geysers project, we did run an extended flow test program on the three largest production wells in June and that confirmed that the wells on the project are still open and ready for production. The wells have been maintained successfully with the pressurized nitrogen charge in the well bore for over six years now. So we feel very solid that this is a good way to keep these wells up and make sure they stay open and ready for production. Data from the flow test was used by GeothermEx to determine the capacity of the existing wells and the reservoir. The four existing wells are capable of initially delivering 458,000 pounds of steam per hour, which has delivered 28.1 megawatts growth or 25.4 megawatts net. These estimates are based on the steam conversion rates from a detailed plant design for a 28.8 megawatts net power plant with hybrid cooling. GeothermEx further estimates that the for the long term operation of the plant we will need an additional two to three production wells over time. Our plan is to reopen historic wells located on the site to provide additional steam at a much lower cost compared to drilling new wells. And generating non conversion of the power plant design is continuing and the hybrid plant design it incorporates both water and air cooling and on capital reduction. This design saves and recycles the maximum amount of water possible for reinjection back into the reservoir. Experience in the Geysers steel that’s shows that if you have 60% or greater water injection that the steam production can be stabilized over the long term, which is extremely important for power generation and it’s one of the key reasons past ever has developed this project were not successful. On the permitting front, our interconnection study, which will allow us to connect to the transmission grid completed the first phase report or the interconnection system impact and facilities study on October 8. The outcome of the study concluded that it is feasible for the project to interconnect into the transmission grid and that the estimated cost is about $1.9 million for the upgrades required at our delivery substation. While this amount won’t be our full cost of interconnection, we expect that the savings of $1 million to $2 million will be achieved compared to past cost estimates. The Sonoma County conditional use permit process is proceeding in parallel and till date has not identified any significant issues. We’re continuing to focus now on securing a power purchase agreement, building a new power plant and selling electricity. The State of California plan to launch this fall and requires 50% of their power to come from renewable energy by 2030. That’s an increase from their current 33%. We believe that this action combined with other new regulations aimed at significant reduction in carbon emissions will spur renewed interest in our project. At El Ceibillo in Guatemala, the modified development schedule was formally approved and signed by the Minster of Energy and Mines in July and that modified schedule was officially incorporated into our profession agreement and signed on October 13. Drilling began on the project with well EC-2, which was halted due to drilling difficulties and was followed up by well EC-2A. The target was the high temperature anomaly defined by the 2014 temperature grading drilling program. EC-2A successfully intersected the zone of high permeability at a depth of 1300 feet or 396 meters. Low counting indicates that the commercial resource has been discovered with the flowing temperature of 398 degrees Fahrenheit or 198.5C. Based on the discovery at EC-2A, two additional wells have been cited to further extend the resource area and to test the deeper horizon in the system. Drilling began on well EC-3 on October 29. So depending upon the results of the two additional wells, combined with EC-2A we will then select the location for our production size well to fully test the resource and determine its size and production characteristics. Now that the modified schedule has been included in our concession agreement and we’ve signed a commercial resource, we will begin the process of identifying and meeting with potential purchasers for our project. That includes of course going back to the group that we previously had an agreement with. The Country of Guatemala has been considering the issuance of a 200 megawatt geothermal RFP sometime during 2016, which of course we fully support. At San Emidio Phase 2, we received our permits for five temperature gradient locations in June and we started drilling in July. Five 1,000 foot temperature gradient wells were completed and all of the wells encountered high bottom hole temperatures and anomalously high temperature gradients. These wells were guided by both seismic data that showed a false control offset at depth and 1970 is vintage shallow temperature gradient holes. The temperature is measured at the bottom of the wells range from 224 degrees Fahrenheit to 274 degrees Fahrenheit. So the temperature gradients in four of the well range from 12.4 degrees Fahrenheit for 108 14.9 degrees Fahrenheit per hundred feet/ In the geothermal world these are very good results and they indicate that an active geothermal system could be in close proximity to these wells. Our second phase of this drilling program that we hope to get done yet this year is to deepen the two most prospective wells. That activity only is currently being permitted with the U.S. Bureau of Land Management. Drilling in this area is weather dependent however. So once we get approval, we’ll have to see when we can mobilize the drill. We have not yet defined the extent of this new anomaly, so we will also be permitting additional temperature gradient wells in the future. Again as San Emidio the second phase interconnection study called the Facility Study was completed in June pending a decision by MD Energy on funding certain upgrades of their transmission system. MD Energy ultimately decided not to fund the upgrades and completed the interconnection system impact restudy on September 28. The restudy determined that the interconnection is feasible, but included an increasing estimated cost due to a change in cost allocation by MD Energy. A median with MD Energy transmission group to discuss these results and anticipated cost took place in late October and a reduction in those costs has already been indicted. The interconnection process will continue with the next phase study to be started within the next month. At our Neal Hot Springs Water cooling project, we did drill a second water supply well during the quarter and flow tested it for a period of six weeks and that achieved a steady state production of about 170 gallons per minute. Recall that the first well we drilled also at found water, but unfortunately that well could not be used under State of Oregon laws as it’s communicated directly with surface water. The minimum amount of water needed for our hybrid cooling system is approximately 200 to 300 gallons per minute for each unit. So that’s our target. Several new drilling targets have been selected and we will continue exploring for our water source that will support the hybrid cooling system. It’s also possible that we could purchase water or get a long term lease of existing surface water or ground water. So we’re looking into that as well. Power Engineers Incorporated completed an initial engineering evaluation of various hybrid cooling methods, which confirm the positive economic impact of hybrid cooling for the project. Our goal is to increase the annual average generation of the plant from the design rate of 22 megawatts up to the PPA contract limit of 25 annual average megawatts and the results of the study support this plan. Last but not least, we recently announced I guess yesterday morning that we’ve completed or we are in the process of completing a purchase of some equipment. We announced yesterday that we signed a purchase agreement for major long lead equipment required to build three binary cycle power plant modules. This equipment represents approximately 70% of the equipment needed for a full power plant and is essentially identical to the equivalent used in our Neal Hot Springs facility. Often how quickly you can build a power plant is determined by how fast specific large pieces of equipment can be built by the manufacture. These are the long lead items that control a construction schedule. By owning this equipment, we will not only reduce our capital cost significantly but we can cut months of the constructions schedule, which is also very important to control cost. Fortunately for us, binary cycle equipment is flexible within a range of resource temperatures and flows. So these equipment packages give us a significant pricing and delivery advantage on our new projects going forward. And that’s my report for operations and development, Dennis? Dennis Gilles Thank you, Doug. Summarizing the notable highlights for the first nine months of 2015, on the financial performance side though all of our facilities experienced warmer than normal seasonal temperatures the entire first nine months of the year, which negatively impacted our generation and with our first major overhaul in over six years at our Raft River project and then having to remove the plant again from service following that overhaul to replace damage bearings we still finished the first nine months with excellent results. Looking at our financial performance, on a consolidated basis our revenues for the first nine months of $21.26 million were slightly up compared to $21.08 the prior year. Adjusted EBITDA for the first nine months of $10.91 million was slightly up compared to $10.86 million the prior year. Our net income as adjusted for the first nine months was $2.28 million and that was slightly up compared to $1.93 million in the prior year or an 18% increase over the prior year. Our cash flow from operations for the first nine months were $9.14 million compared to $7.8 million in the prior year or a 17% increase. We reduced total liabilities since the end of last year by $4.2 million and we ended the first nine months as Kerry had said with cash and cash equivalents of $11.2 million. Looking at the financial performance attributable to US Geothermal only after eliminating our minority interest, which represent our partner’s share of the project at Neal Hot Springs and at Raft River, our net income as adjusted attributable to US Geothermal for the first nine months was $1.25 million compared to $270,000 during the prior year which reflected a 363% increase. The primary source of that increase was roughly $600,000 of increase in net income at San Emidio both due to increased generation and reduced cost and San Emidio is 100% owned by US Geothermal. Looking at taking that same comparison that we got on a net income as adjusted basis for US Geothermal and looking at it on a consolidated basis, the gain in net income from San Emidio was offset by a loss at Raft River of roughly $640,000, but I want to point out that the way our partnership is structured 99% of Raft River profits and losses are attributable to our partner on that project. So that 99% of that $640,000 impact was lost — was represented in the consolidation, but was not represented in US Geothermal’s net income. And I also want to point out that the major overhaul that we had at Raft River is one that occurs once in seven years. On the growth side, at our El Ceibillo project in Guatemala we received a signed modified concession agreement from the Guatemala Ministry of Energy and Mines. We are very pleased to have this resolved this longstanding issue finally resolved. We completed drilling of EC-2A confirming the discovery of the commercial Geothermal resource as Doug said and are currently drilling well EC-3. Our San Emidio 2 project we drilled five 1000 temperature radiant wells are waiting permits from the BLM and two of those wells will be deepened into the identified hit anomaly to confirm the underlying resource in that Southwest Zone. Our WGP Geysers project we received the independent engineers report summarizing the results of the well flow testing which indicated the resource could support the proposed 30 megawatt power plant for up to 54 years. At our Neal Hot Springs project we drilled and tested the first and second water supply wells to support the potential hybrid cooling, it appears we currently have sufficient water to support one of the three units so far. And yesterday we announced that we signed an agreement to acquire three refinery power plant modules at roughly 5% of what that equipment would have cost us to buy it new. The equipment purchase is nearly identical to that installed at our Neal Hot Springs project except newer, this equipment is projected to meet approximately 70% of the major and long lead equipment requirements for the construction of our San Emidio and our Crescent Valley power plants development projects. This purchase will also allow us to lower our cost and shorten our construction time. We continue our evaluation of a number of other potential acquisitions that could contribute to our growth both in the near and long term. Our guidance for 2015, we updated and narrowed and it doesn’t include the projection of revenue that maybe provided by any acquisitions we’re considering. The guidance for 2015 is as follows, for revenue we’re projecting between $30 million and $33 million. For adjusted EBITDA between $15 million and $18 million. Our EBITDA between $15 million and $17 million and our net income between $4 million and $6 million and I do wish to point out all of those are on a consolidated basis. In summary, our cash position continues to be solid with strong cash flows from operations. We continue to have adequate cash on hand to support both our ongoing operations and our early stage development efforts and we continue to add cash to our balance sheet in preparation for our next construction project for acquisition. In acquisition of our three new binary power plant modules, which we announced yesterday will decrease our project cost, improve our project competitiveness and shorten the construction duration for both our San Emidio and present projects. Earlier this quarter, we announced that our Board of Directors had authorized a share buyback over the next year of up to $2 million. We have not had any purchases to date of our stock under that repurchase program. Possessing inside non-publicly disclosed information of a material nature restricts us from making such purchases. Also this quarter we had announced that our Board of Directors had engaged Marathon Capital to act its financial advisor to evaluate opportunities to potentially unlock value of the company for the shareholders. That process has been initiated. In closing the current low energy, excuse me, the current low oil and gas prices that we’re seeing have no impact on our current power plant revenues since those all three plants are fully contracted. We have now had 12 consecutive quarters of positive EBITDA and cash flow from operations. Our fleet of power plants continues to perform well. We’re pleased with the performance of our resources and we’re excited and optimistic about the growth opportunities we’re currently evaluating. Thank you for your continuing support and operator I would like to now open the call for questions. Question-and-Answer Session Operator At this time, we will be conducting a question-and-answer session/ [Operator Instructions] Our first question comes from the line of Jim McIlree of Chardan Capital. Please proceed with your question. Jim McIlree Thank you. I guess good morning, to you. Dennis Gilles Yes it is. Jim McIlree And are the cost — is the cost of flooring the equipment that you purchased is that significant or meaningful? Dennis Gilles No Jim, the cost that we will incur is relocation of equipment from where it’s currently stored to our San Emidio facility. At the San Emidio facility we have both internal and external storage to adequately house that equipment. So on an ongoing basis after the equipment is relocated, we won’t have any storage cost per se. Jim McIlree And are relocation cost, is that a significant amount? Dennis Gilles Relative to the price that we paid for the equipment it is. If it’s $7 million it will be somewhere between probably $0.5 million and three quarters of a million to relocate all the equipment. Jim McIlree And so is that something that will be expensed or do you get the capital right there? Dennis Gilles I am looking at our CFO. Kerry Hawkley I’ll get back with you on that one. Jim McIlree Okay. Great. And then as far as Q4 goes, are there any special outages, maintenance, any issues that we should — that you can remind me of just in case I don’t want to be too aggressive or pessimistic on that? Dennis Gilles Q4 is our high money quarter and we keep all the units running and generate the maximum generation that we can. There are no outages planned during the quarter. Jim McIlree Great. Great. And then similar question for next year, do you have any planned major or semi-major maintenance for any plant? Dennis Gilles No major outages planned at any of the plants. We do have our screen outage that we take all the facilities down and do kind of our… Doug Glaspey Five to six days usually Jim on our spring outage reach unit. Jim McIlree But that’s the normal spring outage that you guys have. Dennis Gilles Yeah it’s not like what we experienced on Raft River, those occur one in every seven years and Raft was seven years old. The other two plants started in late 2012 so they’re a long way away from their major outages. Jim McIlree Okay, great. And as far as the stock buyback goes, are you just waiting to get out of a higher period to implement funding or does the Marathon process has to be complete before you can do anything. Dennis Gilles We don’t believe the marathon process currently impacts our ability to purchase the stock. We do have as noted material none publicly disclosed information regarding another transaction that were looking at and that limits our ability to do the stock repurchase once we’re outside of that and that’s behind us then it’s our intent to proceed forward with our stock repurchases. Doug Glaspey But Jim it would be subject to our normal blackout period that we’re restricted I believe three 30-day periods during the year that we can actually purchase. Jim McIlree Right of course, okay and then last one is there an estimated time when you think the Marathon process would be complete? Dennis Gilles I don’t have a projection for you on that. The process has been initiated and as we noted in our press release, we do not intend to comment further regarding the evaluation of the strategic alternatives unless the Board decides to proceed forward with any specific transaction. Jim McIlree Al right. That’s it for me. Thanks a lot. Dennis Gilles Great, thanks Jim. Appreciate your support. Operator Our next question comes from the line of Peter Rabover of Artko Capital. Please proceed with your question. Peter Rabover Hi, guys, can you hear me? Dennis Gilles Yes we can. Peter Rabover Hey, congratulations on the DLA, I really like that, just a couple of questions on that. So would that make your PPA bids more competitive given the low cost I guess low capital investment, is that how you’re looking at it? Dennis Gilles Yes it allows us two things. It either allows us if you we had a PPA to increase the margin on that project, but since we don’t have a PPA it give us the flexibility to dramatically lower our price allowing us to be more competitive in obtaining a PPA. Peter Rabover Okay, that’s great. And maybe you can give an update, given how many projects you have in I guess like ready to be fired up on your financing strategy since what’s happening with conservation with banks what kind of financing partners are you looking at. You do have some cash but it sounds like you’re going to more money than this. So I would love to hear some color on that? Dennis Gilles Well our intent depending on each product is specific, our intent is to project finance each project three of the four projects that we have in our development pipeline qualify for the investment tax credit so our intent would be to bring in a tax equity partner so that we can monetize that tax credit that is 30% investment tax credit. So between the 30% investment tax credit funds being monetized and between the construction fine or the construction to firm financing not recourse financing for the project which were roughly to be 70% to 75% of the project cost between the two of those that will cover the majority of the capital requirements for the project. Peter Rabover Okay, but you’re talking about acquisitions and do you have financing partners lined up for things like that? Dennis Gilles We do not have financing partners lined up, no we don’t. We have some third parties that we have talked to but we do not have partners lined up no. Peter Rabover You have I guess the whole project that does not have credit I assume that the Guatemala project, do you have any thoughts on that the financing there? Dennis Gilles Yes for Guatemala as we previously announced it’s our intent to bring in a in-country partner as our equity partner on the project and we have not pursued that yet because the primary thing was we were waiting resolution of our concession agreements which that was very long process well over two years and then we need to secure our power purchase agreements with those two in hand and with the recent confirmation of the commercial resource then we could then pursue and lock in a equity partner for that project. Peter Rabover Okay. Then just on the deal that you guys made for the equipment purchases that is very interesting are there more things like that out there like or that is just a very unique project or unique purchase? Dennis Gilles In the binary field that’s the only one that we’re aware of that is out there. Peter Rabover Okay. Dennis Gilles New equipment again this is equipment we are extremely familiar with as we noted in our press release the developer had bought equipment for six plants the three that were installed is essentially a replication of our Neal Hot Springs plant, these are Atlas Copco turbines. Atlas Copco is a $10 billion plus company. Very solid company. It’s the turbines that we have, the turbines, the generators and all the other associated equipment’s that we have at our Neal and our San Emidio projects already will familiar with that will familiar with the turbine with the equipment manufacturers so that one for us is a home run. So we are looking at other opportunities out there in order to try to improve our competitiveness and advance our securing power purchase. Peter Rabover Okay, great. Just a couple of more so on the Geysers it sounds like based what the report you guys got it sounds like you are proceeding with the [indiscernible] option? Dennis Gilles That is correct. We’re proceeding with the option of building a new plant. Peter Rabover Okay, great and then just on the Marathon Capital thing, how do you anticipate that putting that out to shareholders is that going to be a report at some point like it is just curious on that? Dennis Gilles That is actually an item I can’t speak to Peter, the our board of directors is the one working with Marathon in this process to with the intent to determine whether or not there is unrealized value for our shareholders that is not the unrealized the way the markets responding to our current share price. So until they complete their process it I am not in a position to say it. Peter Rabover Okay, great. Well hey you guys are doing great, keep up the good work with the deals and I will just get off the line and let somebody ask more questions. Dennis Gilles Thanks Peter. Operator Our next question comes from the line of Bryan Lee of Private Management Group. Mr. Lee Please proceed with your question. Bryan Lee Hey thanks for taking my question. You know couple of months back the State of Ohio put out a ruling that they are going to start taking into account the reliability of the power source when determining purchase price agreements basically putting a premium on that base loads stable production. Do you see that trend stretching on or do you heard any other states echoing those comments would be my first question and then maybe if you can take a little deeper and talk about California and how they are kind of taking into account where your PPA negotiation talks? Doug Glaspey Sure this is Doug Glaspey. It’s a very good question because as you know our chief I guess rivals in the renewable business are wind and solar which are intermittent resources. What we’re seeing certainly is that California is coming to that same conclusion. They have bought tremendous amount of wind. They have a lot of solar and more solar coming and it is giving them some good reliability problems because most of the power plants that are coming off line that need to be replaced are base load power plants. Whether they are nuclear plants, coal plants or once through cooling plants along the coast. So we think there is going to be a little bit of a change especially in the California market. I think because of them going a little too far maybe with wind and solar purchases all the other states are looking to see what happened and they want to make sure that doesn’t happen to them. So we view that very positively, glad to see that Ohio is making that move, it is certainly in talks about it and it has been referenced in the legislation in California not directly specified but certainly referenced that grid stability and base load is an important aspect of the renewable program. Bryan Lee Great, great. And then I don’t know if you can put numbers around this, but on the Geysers project can you just maybe give us directionally where you think that PPA is going to come out maybe compared to one of your existing PPAs? Doug Glaspey Not in a position to give you that Bryan. Bryan Lee Okay. Doug Glaspey I’m sorry. Bryan Lee That is fine. Doug Glaspey Until we have the PPA negotiated I am not in a position to speculate on what the price is going to be. Bryan Lee Okay, great. All right, great quarter. Thank you. Doug Glaspey Thank you. Operator There are no further questions in audio portion of this conference. With no further ado I would like to turn the conference back over to management for closing remarks. Dennis Gilles Well, thank you operator and thank you to everybody on the call. We appreciate your continuing support. We’re excited about the some of the current announcements we are excited about the things that we had in the works that we hope to be able to announce to you in the not too distant future and we’re continuing to work diligently in order to try to increase the value of — the value of your investment and the value of the shares that you hold and the value of our company as a whole. Thank you for your continuing support and we wish you all the best of the upcoming holidays and as we wind out this year. Thank you operator and with that I conclude my comments. Operator This concludes today’s conference. Thank you for your participation. You may disconnect your lines at this time and we ask that you have wonderful rest of your day. Dennis Gilles Thank you.

National Fuel Gas’ (NFG) CEO Ronald Tanski on Q4 2015 Results – Earnings Call Transcript

National Fuel Gas Co. (NYSE: NFG ) Q4 2015 Earnings Conference Call November 6, 2015 11:00 AM ET Executives Brian Welsch – Investor Relations Ronald Tanski – Chief Executive Officer David Bauer – Treasurer and Principal Financial Officer Matthew Cabell – President of Seneca Resources Corporation Carl Carlotti – Senior Vice President Analysts Kevin Smith – Raymond James & Associates, Inc. Holly Stewart – Howard Weil Inc. Chris Sighinolfi – Jefferies LLC Tim Winter – Gabelli & Company Becca Followill – US Capital Advisors Operator Good day, ladies and gentlemen, and welcome to the Q4 2015 National Fuel Gas Company Earnings Conference call. My name is Mark, and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I’d now like to turn the conference over to your host for Brian Welsch, Director of Investor Relations. Please proceed, sir. Brian Welsch Thank you, Mark, and good morning. We appreciate you joining us on today’s conference call for a discussion of last evening’s earnings release. With us on the call from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer; Dave Bauer, Treasurer and Principal Financial Officer; and Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open up the discussion to questions. The fiscal 2015 earnings release and November Inventor Presentation have been posted on our Investor Relations website. We may refer to these materials during today’s call. We would also like to remind you that today’s teleconference will contain forward-looking statements. While National Fuel’s expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening’s earnings release for a listing of certain specific risk factors. With that, I’ll turn it over to Ron Tanski. Ronald Tanski Thanks Brian and good morning everyone and thanks for joining us today for a discussion of our fiscal 2015 results. Last year at this time, I talked about National Fuel having achieved new fiscal year records for recurring earnings and cash flow for our 2014 fiscal year. Over the last 12 months lower commodity prices decreased our GAAP earnings and cash flow for our 2015 fiscal year. However operating results across each of our reporting segments remain strong. While we focused on our growth opportunities in our upstream and midstream segments, our utility and energy marketing operations continue to be an important part of our integrated strategy. In our utility we’ve increased our investment activity to replace older pipelines that were more prone to developing leaks and were continuing to develop new customer information and billing system to assure continued service quality for our customers, earnings in the utility or just slightly lower compared to last year. Our Energy Marketing segment had another good year, while passing the benefit of lower commodity prices along to their customers this segment still accomplished a million-dollar increase in earnings for the year. In our upstream segment at the Seneca Resources it was lower commodity prices that were the earnings driver for the year. The majority of the decrease in year-over-year earnings in the segment was caused by lower crude oil prices during the year. As we look forward to our fiscal 2016 we have strong hedge book for a large portion of both our crude oil and natural gas production which should protect a large portion of Seneca earnings and cash flow. What’s more important though, is that Seneca continuing to focus on cost control and its development operations that control is evident from the $0.96 per Mcfe of finding and development costs for the last year and particularly our $0.79 per Mcf of finding and development costs in the Marcellus. Our ability to continue development across our acreage of these costs puts us in a good positioned for a long period of development in the Marcellus. And this development of our own acreage supports the integrated growth strategy of our pipeline businesses. Our focused on cost control will continue as we timed the drilling and completion of our wells to match the new pipeline capacity that Seneca is coming online over the next two years. In our pipeline and storage segment I’m happy to report that three pipeline projects that we’ve been talking about for a while are now in operation. Our West Side expansion project along our Line N corridor when into service over the past few weeks and we are now shipping an additional 175,000 dekatherms of production per day for a couple of producers one of which is Seneca Resources. This project with a combination upgrade to our existing pipeline system under our modernization program and an expansion project. The project came in on budget at $86 million and the annual revenue associated with the new contracts is $8.8 million. This project was the fifth successful expansion of our Line N system since 2011. We also put our Tuscarora Lateral project into service this week, this was a project that allowed us to connect our Empire Pipeline with our supply company storages and sell a combination of storage and firm transportation capacity. The project also came in on budget at $60 million and has associated incremental annual revenues of $10.9 million. The other project that we’re phasing into service right now is our Northern Access 2015 project. This project, which is paired with a project by Tennessee Gas Pipeline, on our jointly owned Niagara Spur Line, will allow Seneca to move an additional 140,000 dekatherms per day of production to Canada. $40,000 dekatherms began flowing this week and the remainder will be ready to flow the end of the month. At a cost of $67.5 million dollars this project was also on budget that will generate revenues of $13.3 million annually. Our Northern Access 2016 project continues to move through the permitting phase because we made some location changes for some facilities on the project, we had to amend our FERC application. The changes weren’t major; however, they will likely require additional scoping by FERC. As a result we extended our certificate request date from December 2015 to February 2016. Assuming we receive a certificate in February or March we would still expect to get the project in service late in 2016. As each one of the projects that I referred to has taken years to reach their in-service dates, we continually look for new expansion projects to continue our growth. Last month, we announced an open season for a new project that we’re calling Empire North. It’s a project that’s designed to bring gas into the Southern end of our Empire Pipeline system and move it North. New interconnects are possible at Corning New York, or in Tioga or Potter Counties, Pennsylvania. We had a number of inquiries from possible shippers in those areas, so we put together the open season to try to transform some of those inquiries into commitments. Depending on the level of commitments and delivery point preferences we could handle up to an additional 300,000 dekatherms per day of throughput, while low commodity prices can be a challenge for our upstream business we have seen increased average use per customer on our Utility business and continuing demand for more pipeline capacity from producers looking to move their gas to higher-priced market. The next year, we will begin construction of the Northern Access 2016 project, which, in addition to benefiting supply in Empire will move Seneca’s production to a higher price market in Canada, we have a great hedge book, strong balance sheet and access to ample amounts of short-term credit plus our regulated operations provide a measure of stability to our earnings and cash flows. We’ve had great plan to take advantage of our unique mix of assets along commodity prices are at their low point in the cycle, we’re confident that our integrated approach to developing our acreage and building in the infrastructure needed to deliver our production to premium price markets will create significant long-term value for our shareholders. I’ll turn the call over to Matt Cabell to cover some of the Seneca details for the year. Matthew Cabell Thanks Ron and good morning everyone. For the fiscal fourth-quarter Seneca produced 37.6 Bcfe, which is 8 Bcfe less than last year’s fourth quarter. We voluntarily curtailed approximately 12.8 Bcf of potential spot sales due to low prices. Absent those curtailment’s production would have over 50 Bcfe for the quarter. In California production for the quarter was nearly flat to last year’s fourth quarter, despite a significant reduction in capital spending for the fiscal year. Looking to the future I’m pleased to report we’re in the process of closing another farm-in deal with Chevron in the North Midway Sunset field. Under the agreement, we are committed to investing $12 million over the next three years. This acreage is very close to our existing North Midway development and we are confident that we can develop it effectively and economically even at current oil prices. We’ve also called small acquisition adjacent to our South Midway Sunset area and are negotiating a second deal in that area. All three of these deals were structured in a way that minimizes upfront spending and instead allows us to deploy capital to develop the assets over several years. With these deals, we expect our overall California production to be relatively flat or up modestly over the next five years. Moving on to the Marcellus. In the Clermont/Rich Valley development area we have now drilled a total of 111 wells and completed 62. These wells continue to deliver consistent results in line with one type curve. In fact, the P10 to P90 EUR ratio is 1.4, which means the difference between the strongest 10% of our wells and the weakest 10% is only 1.4 times. This consistency in well results gives us a lot of confidence as we pursue our integrated growth strategy. Our fiscal 2015 development well cost was $5.7 million for a 37 stage well with the 7300 foot lateral length. As we move into fiscal 2016, we have negotiated a new frack contract, and have achieved substantial efficiencies in water handling. Therefore, I expect fiscal 2016 well cost to be down another 10% to 15%. Moving now to the Utica Point Pleasant. We finished drilling our first Clermont area Utica horizontal. The lateral length is approximately 5700 feet, and the AFE total cost to drill, complete and equip is $12 million. We drilled it to TD in 18 days so the phase was well under budget. We planned to frack this pad in the third quarter of fiscal 2016 and should have a flow rate shortly thereafter. We’ve completed our year-end reserves audit and for the fiscal year we replaced 373% of production to end the year with 2.3 trillion cubic feet equivalent of proved reserves. Our fiscal 2015, finding and development costs was $0.96 per Mcfe. On the marketing front, our strategic focus on long-term firm sales and hedging served us well in fiscal 2015. Our average after hedging gas price was $3.35 for the quarter and $3.38 for the fiscal year. Looking forward to fiscal 2016, we now have a 120 Bcf of our gas production locked in both physically and financially at an average price of $3.45, so we are well-positioned should low prices persist this year. In conclusion, our Marcellus development program is delivering the results we expected at a significantly lower cost. While overall finding and development cost is less than a $1, Marcellus F&D is only $0.79 per Mcf. This has lowered our breakeven price to $2.03 at Clermont specifically and less than 250 across a broad swap of our acreage. With firm transportation building to 900 million cubic feet by the end of 2017 we can expect decent returns at futures pricing and very good returns on large production volumes when Nymex gets back above $3. With that, I will turn it over to Dave. David Bauer Thanks Matt, and good morning everyone. As you read in last night’s release National Fuel reported a net loss for the fourth quarter of $2.22 per share. There were three items of note in the quarter that impacted earnings. First, as expected, the decline in commodity prices led Seneca to record another non-cash ceiling test charge of $2.83 a share. Going in the other direction Seneca had a few adjustments to deferred income taxes that improved earnings by $0.15 a share. The most significant of these adjustments related to Seneca’s capacity on the Northern Access 2015 project which will transport its production into Canada. As its Canadian sales increase, less of Seneca’s revenues will be allocated to its Pennsylvania income tax return, which will reduce future tax liability. Lastly, as a result of the net loss we experience this year the restricted stock grants made to our executive team for the three-year cycle that ended September 30 will not vest. Therefore we reversed about $8 million or $0.6 per share of long-term incentive comp expense, which was also a benefit to earnings. Excluding these three items results on operating basis were $0.41 per share. So down from the prior year mostly due to the decline in crude oil prices in the E&P segment. Our consolidated operating results for the quarter were right in line with our expectations. At Seneca both production and per unit cash operating costs were right down the middle of our guidance ranges. Per unit DD&A expense was actually below our guidance range thanks to the continued improvement in Seneca’s finding and development costs the Ron and Matt described earlier. Earnings at our midstream businesses were relatively flat compared with last year. At the gathering business earnings were down his overall volumes and revenues track Seneca’s production. At the regulated pipeline of storage companies continue demand for transportation services on our system cause revenues to grow by about $2.4 million. Looking ahead fiscal 2016 should be a good year for our midstream businesses. Gathering revenues will track Seneca’s production in the three projects Ron described earlier we had about $25 million in incremental revenues in the pipeline and storage business in fiscal 2016. However, keep in mind that as I said on the last call a portion of that increase will likely be offset by a variety of smaller items including typical re-contracting on both pipeline systems and an assumed return to normal weather in our service territory. In addition, this past quarter Supply Corporation reached a new rate settlement with the chippers. As part of that agreement supply agreed to reduce its base rate by 2% effective November 1, 2015. An additional 2% reduction will be made effective November 1, 2016 for a cumulative reduction of 4%. The expected impact fiscal 2016 revenues as a result of the settlement is about $3 million. The agreement also contains a comeback provision whereby supply agreed to file a general rate case no sooner than September 30, 2017 and no later than December 31, 2019. Turning to guidance, we now expect fiscal 2016 consolidated earnings will be in the range of $2.85 to $3.15 per share excluding ceiling test impairment charges. At the midpoint this is a decrease of $0.15 from our previous guidance. Substantially all of the changes attributable to a decrease in the commodity price assumptions reflected in the forecast. Specifically we are now assuming NYMEX natural gas prices averaged $2.75 per MMBtu, down $0.50 from the previous forecast. We’re also lowering our NYMEX crude oil assumption to $50 a barrel down $5 in the previous forecast. Going in the other direction is an improvement in our DD&A rate. Thanks to strong reserve bookings at year-end and continued improvement in F&D costs, we now expect DD&A expense will be below the midpoint of our $1 to a $1.10 per Mcfe guidance. Seneca’s production forecast has been updated to reflect some new farm sales agreements that were executed in the last three months. The new ranges is 161 to 232 Bcfe, this is wider than normal range which reflects the uncertainty around Appalachian gas pricing and our ability to sell spot volumes and an acceptable price. Our guidance reflects the full range of potential outcomes if we saw 100% of our spot volumes will be at the high end of the range if we don’t sell any spot volumes will be at the low end. All of our remaining major assumptions for next year with respect Seneca and the rest of the businesses remain the same. As Matt indicated earlier we have a great hedge book for next year with a significant portion of our production hedged at prices well above current market levels. In total we have hedges covering 120 Bcf of gas sales at 3.45 per Mcf and 1.4 million barrels of crude oil at 88.24 per barrel. At the midpoint of our production guidance were better than 65% hedge for gas and about 50% for oil. Turning to capital spending we made some small changes to the budgets of the individual segments, but our overall consolidated capital budget is still $1.1 billion to $1.3 billion. Seneca’s updated budget of $400 million to $450 million reflects the expected benefit of the new frack contract Matt mentioned earlier. Utilities budget was updated to a range of $90 million to $210 million to reflect the timing of spending on our new customer billing system. There were no changes to the gathering our pipeline and storage businesses capital budgets. And all the details on our capital spending by segment can be found in the new IR deck on our website. Based on our updated forecast we still expect an outspend in fiscal 2016 in the range of $500 million to $600 million. As you can see from our balance sheet, we had $113 million in cash on hand at year-end, which will cover some of that outspend, but we will need to raise capital to cover the rest. As we’ve said on prior calls, we’re evaluating a number of financing alternatives including a master limited partnership and other alternatives that could take advantage of the large amount of private capital it’s waiting on the sidelines in the energy space. But we don’t have anything new to report on this call, the process is still ongoing and we will keep you up-to-date as we move through the year. In terms of the timing of the financing need most all of our outspend in fiscal 2016 is tied to the Northern Access 2016 project. Assuming we receive our certificate to construct it by the Spring, we’ll start making significant construction expenditures early next summer and continuing through late fall. Thus we do have a little bit of time to make the financing decision. Our short-term credit facilities give us the flexibility to access the capital markets when it makes the most sense. This past September we increased the size of a credit facilities by $500 million. In total we now have access to $1.45 billion of short credit substantially all of which is undrawn. As of yesterday we had about 25 million of commercial paper outstanding. So in closing our low commodity prices will make fiscal 2016 challenging for producers, but National Fuel’s integrated structure, long-term vision and pragmatic approach to hedging and capital deployment has us well-positioned to endure what may be trying times ahead in the industry. With that, I’ll close and ask the operator to open the line for questions. Question-and-Answer Session Operator [Operator Instruction] Your first question comes from Kevin Smith from Raymond James. Please proceed. Kevin Smith Hi, good morning, gentlemen. Ronald Tanski Good morning, Kevin. Kevin Smith Congrats on all of the positive efforts you’re making in a tough tape. Matt, as you’re working down your Marcellus well economics in the WDA – and clearly, you made a lot of progress there. But however, if we’re in a natural gas price – call it a $2.30 price environment, similar to where the prop month is today – do you expect to slow down drilling? Or is it a price you’re okay with? Matthew Cabell Yes, Kevin, we’re really more focused on timing our drilling and completions to fill the pipeline capacity that we’re going to have from Northern Access 2015 now and then Northern Access 2016 roughly the end of 2016. So that’s really what drives our activity level rather than current pricing, now the timing of our completions is at least somewhat dependent on current pricing because we can delay some of the completions closer to the date when the Northern Access 2016 comes on. Kevin Smith Got you. And then one last question on drilling, and I’ll jump back in the queue. You’ve increased your lateral lengths pretty substantially, over the last three years, as well as most people in the industry. But now that you’re at 7,000 feet, how much longer do you think you can go, or are you comfortable going? Matthew Cabell Yes. So as we look forward in the area around Clermont – so sort of Clermont and Hemlock and Ridgeway – we’re estimating that we’re going to average something closer to 8,800 feet. For fiscal 2016, I think around 8,000 or it’s going to be longer than that, over time. Kevin Smith Okay, thank you very much. Operator Your next question comes from the line of Holly Stewart from Howard Weil. Please proceed. Holly Stewart Good morning, gentlemen. Couple questions this morning. Just going to the slide deck, Matt, I know you talk about building productive capacity, with Northern Access 2016 coming online. Certainly not trying to pin you down on 2017, but just trying to get a sense to how we should think about that productive capacity translating into production in 2017? Matthew Cabell I guess what I think you are asking Holly is what we think we will be able to produce when we have Northern Access on in 2017. Is that right? Holly Stewart Yes, I’m not trying to pin you down on numbers, per se. But you’ve got a – that’s a big amount of pipeline capacity. And just trying to think about how we should roll some of that through? Ronald Tanski Yes, I think the way to think about it Holly is we probably won’t fully utilize all that capacity the day Northern Access 2016 comes on line, but it won’t take tribally long for us to get to the point that we fill all of it. Holly Stewart Okay. Then maybe looking, also, at the slide deck, slide 9 breaks down that Tier 1 area, and WDA, into the three different buckets. I think slide 10 is a little hard to decipher, but we’re just trying to figure out how we should think about those three areas, in terms of your development plan in 2016 and 2017? Ronald Tanski Yes, so you’re asking about 9 and the… Holly Stewart I think you’re trying to get at it in slide 10, with the wells, but it’s hard to compare the slide 9 and 10. Ronald Tanski Yes, so slide 10 is a zoom in – a great deal zoomed in from slide 9. Holly Stewart Sure. Ronald Tanski What you see in slide 9 is it’s virtually our entire Western development area and slide 10 is just focused on Clermont. Holly Stewart Okay. So as we think about those three areas, how should we think about that development plan playing out? Ronald Tanski What you say three areas, you mean the Clermont/Rich Valley, Hemlock, Ridgway going down there? Holly Stewart Yes, the three areas in the Tier 1. Ronald Tanski Yes, you should think about Clermont/Rich Valley being our focus for the next 12 to 18 months and then we’ll gradually work your way down into Hemlock some time in fiscal 2017. Holly Stewart Okay. And then maybe one, just if I could, on the financing, Dave. You mentioned some – a lot of private capital. I know you’ve put the – I think it was an additional $500 million revolver, or maybe it was $750 million revolver in place. Is there just some color you can give? I mean could you do this all kind of bridge the CapEx to cash flow deficit, all through debt, without much of a ratings movement? Or how should we think about that? David Bauer Yes, I think, well the idea behind putting the additional committed credit in place was to give us flexibility to access the markets when the time was right. I guess our feeling is when you look at the size of the Northern Access 2016 project it’s unlikely we could finance that and keep our current ratings. So that’s the emphasis for pursuing other avenues of capital. Holly Stewart Okay, great. Thanks, guys. Operator Your next question comes from Chris Sighinolfi from Jefferies. Please proceed. Chris Sighinolfi Hey, good morning. Ronald Tanski Good morning, Chris. Chris Sighinolfi Thanks for the color already provided. I do have a couple questions. I guess following up on where Holly left off, given just the current market conditions, both for gas prices, but also, if you’re watching what’s going on the Midstream MLP space, it has been pretty volatile. So I’m just wondering, Ron, if you have revised thoughts to share, with regard to the Northern Access 2016 project? The capital need, and the thought process or decision tree around how to finance it? You had previously talked about Midstream MLP, you mentioned that today, you mentioned private sources. If you could just give us a little bit more color, in terms of like how you and the executive team and the Board think about each of those? Realizing you have, to Dave’s earlier point, maybe six to nine months before you really have to make a full decision on it? Ronald Tanski Yes, Chris it’s just a matter of lining up all the various options and looking at the various costs or the attractiveness of each at the time that we are going to need to enter the market as you mentioned the MLP space is a little bit volatile right now, but what we are doing and then as Dave mentioned, first of all we’ve got that in our pocket the short-term credit facilities that really allow us to be flexible in the actual timing of any financing that we have coming up. So as Dave mentioned the private capital market, the infrastructure funds have always exhibited a strong interest in our asset. So we’ve had ongoing dialogues with a number of different sources and we will just line those up and see which one fits the bill at the time and as you mentioned the big capital need comes in the summer. So that’s we are just working at as we go along. Chris Sighinolfi Okay. And in terms of, when you talk about private, are you envisioning if – in a completely hypothetical sense, obviously, at this point in time. If we were to think about that route being selected, are – should we be interpreting that, Ron, to think about some level of sort of project financing on that basis? Where private maybe has an interest in that project individually? Or are you talking about private investment in National Fuel? Ronald Tanski It’s more on a project type basis, and I guess the other thing to throw in there is always the possibility of partners on various projects. So there’s a whole host of options. Chris Sighinolfi Right, okay. All right. I won’t beat that any further. I appreciate the color on it. I guess my next two questions are for Dave. Dave, I really always appreciate your comments. They’re very detailed, relative to the disclosure we get from so many other companies, it’s incredibly helpful. David Bauer Thank you, so much. Chris Sighinolfi So thank you for that. You had mentioned NFG supply would trim its rates, in several phases, over the next couple of years. I’m wondering – obviously, the impact there relatively small. I think you said $3 million in revenue? But I’m wondering, as you look at the rest of the system, are there any know contract roll-offs, or likely settlement reductions of a similar nature, on any other aspects of the system that we should be aware of? David Bauer Yes, we have a few re-contracting issues that we expect this year. They are not huge dollars maybe in the $5 million range total. Chris Sighinolfi Okay. And when would those – did the discussions around those re-negotiations already commence? Or is that something coming up? David Bauer They’ve actually already happened. Chris Sighinolfi They have, okay. And to your thinking, the net impact of those finished discussions, it’s $5 million? David Bauer Right. Chris Sighinolfi Okay. David Bauer I mean rough quarter magnitude. Chris Sighinolfi Yes, okay. And then also, you had mentioned this gradual shift in Seneca production or sales moving from Pennsylvania to Canada. Obviously, we’ll see more of that gradually, over time. I don’t know if you could quantify for us what the magnitude of the tax differentials would be, as you’ve thought about that shift? David Bauer Yes, I am looking at our Vice President of Tax here, as how do best answer to that question. Matthew Cabell The Canadian sales would really be not cash that all because Seneca doesn’t have a presence in Canada. In the Pennsylvania tax rate is 9.9%. So that’s the math is involved. Chris Sighinolfi Okay, and can we just look at the firm sale that you have net to, let’s say, the done price, or whatever, as effectively de facto Canadian sales? When we think about firm segments? Or how should we gauge what magnitude of sales actually sell in Canada? David Bauer I think you can look at the capacity still we hold in the Canada is the proxy for that. Chris Sighinolfi Okay. David Bauer And then whatever percentage of that is used which ultimately 100%. Chris Sighinolfi Okay, perfect. And then I don’t know if she’s there with you guys, or listening. But just wanted to congratulate Anna Marie on her pending retirement. Always been really helpful, appreciated her thoughts on all things Utility-related. So congrats to her, and best wishes to Carl. Carl Carlotti I am here Chris, thank you. And I am leaving you in good hands with Carl. Chris Sighinolfi Thanks a lot guys, appreciate the time this morning. Ronald Tanski You bet. Operator You next question is come from the line of Tim Winter from Gabelli. Please proceed. Tim Winter Good morning, and thanks for taking my questions. Ronald Tanski Good morning, Tim. Tim Winter I wanted to clarify, on Slide 18 that the top end of the earnings range is assuming that all 70 of that Bcf is sold at $1.75. Is that what I heard? Ronald Tanski Yes, that’s right Tim. Tim Winter Okay, and then on Slide 19, the – how should we think about the pricing of that 900,000 dekatherms a day in 2018? Is that – the bulk of that just future Dawn pricing? Or… Ronald Tanski Yes, that’s there is a big chuck of that that’s going to be future Dawn pricing. So both the Niagara Expansion piece and the Northern Access 2016 piece, now that’s not to say we might not put some firm sales agreements and have them indexed to NYMEX instead of Dawn. But as you’re looking at things in the future that we don’t already have contracted Dawn’s probably your best proxy. The orange piece on there that’s Atlantic Sunrise, we’ve got most of that sold under firm contracts that are premium to NYMEX. Tim Winter Okay, great. And then just one more follow-up question, on the financing, and the various alternatives that you’re thinking about. Might one of them be a non-core asset sale? Are there any pieces of your business that, over time, have become less, “core”? Ronald Tanski Tim as we look at pretty much all of our assets, and you look at the map where they all overlay each other, we’re in pretty good shape with all our assets now. The one issue or not issue, the one opportunity could be the remainder of the timber assets that we have in Pennsylvania hardwood timber assets. If you recall, we sold probably at least half of those assets when we or maybe a little bit more, when we sold those to do the financing for the Empire Pipeline. When we initially acquired that, we did a like-kind exchange. So there’s – probably the most likely one asset that would be sizable enough or meaningful enough in terms of an asset sale. The rest of the business I mean all of the pipelines and storages and utility work pretty well and when we continue to focus on the expansion of all the pipeline assets that we have. Tim Winter Okay, great. Thank you. Operator [Operator Instructions] Your next question comes from Becca Followill from U.S. Capital Advisors. Please proceed. Becca Followill Good morning. David Bauer Good morning, Becca. Becca Followill On the credit rating, would you be willing to sacrifice the credit rating? David Bauer Likely no, Becca. We have regulatory commissions that would expect us to be at investment-grade credit rating, so that would be our intent. Becca Followill Okay, thank you, that’s what I thought. I just always have to ask. And then Matt, you talked about that you could generate decent returns at the strip. What is decent? Matthew Cabell Yes, so if you – we have a slide that shows, probably the best way to answer the question is to reference slide, what slide is that Ron, with the little table of economics? Ronald Tanski 9. If you go to slide 9, you can kind of get a sense for our returns at varying realized prices. Becca Followill Okay. And then just, I know there’s been several questions on this. But again, on the firm transportation capacity. So you don’t see any scenario, assuming that the strip holds, that you would be left with a material amount of FT that you would be holding the bag for, for more than a year or so? Matthew Cabell Yes, not for more than a year or so and even in that one-year we are talking about it, probably wouldn’t be a terribly large volume that we would have to release. Becca Followill Thank you. And then last question. Any progress on removing those indentures that prohibit you guys from raising debt? Ronald Tanski Yes, we’ve had a process that’s been ongoing over the past few months to try and find a solution that works for everyone, unfortunately we haven’t had a great deal of luck with that which is why also partially why we increased our credit lines by the $500 million that we did. It’s something that we will still continue to explore and if we got to the point where we were looking to do a long-term debt issuance, we could always seek a temporary waiver, but I guess that’s where we stand on it. Becca Followill Okay, thank you. That’s all my questions. Operator I’d now like to turn the call back over to Brian Welsch for closing remarks. Please proceed. Brian Welsch Thank you, Mark. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 PM Eastern Time on both our website and by telephone and will run through the close of business on Friday, November 13, 2015. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1-888-286-8010, and enter passcode 17759908. This concludes our conference call for today. Thank you and goodbye. Operator Ladies and gentlemen, thank you very much. Your conference call is concluded. You may now disconnect and have a great day.