Tag Archives: construction

ALLETE’s (ALE) CEO Al Hodnik on Q4 2015 Results – Earnings Call Transcript

Operator Good day and welcome to the ALLETE Fourth Quarter 2015 Financial Results Call. Today’s call is being recorded. Certain statements contained in this conference call that are not descriptions of historical facts are forward-looking statements, such as terms defined in the Private Securities Litigation Reform Act of 1995. Because such statements can include risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements. Factors that could cause results to differ materially from those expressed or implied by such forward-looking statements include, but are not limited to, those discussed in filings made by the company with Securities and Exchange Commission. Many other factors that will determine the company’s future results are beyond the ability of management to control or predict. Listeners should not place undue reliance on forward-looking statements, which reflect management’s views only as the date hereof. The company undertakes no obligation to revise or update any forward-looking statements or to make any other forward-looking statements whether as a result of new information, future events, or otherwise. For opening remarks or introduction, I’d like to now turn the conference over to ALLETE President and Chief Executive Officer, Alan R. Hodnik. Sir, please go ahead. Al Hodnik Good morning everybody and thank you for joining us today. With me is ALLETE’s Chief Financial Officer, Steve DeVinck. Before I began with my remarks, I would like Steve to briefly cover the 8-K we issued last week relating to a non-cash impairment charge at ALLETE Properties. Steve? Steve DeVinck Thank you, Al. Last week we announced that 2015 results were reflected $22.3 million after-tax or $0.46 per share non-cash impairment charge at ALLETE Properties on legacy Florida real estate investment. In response to market conditions and recent transaction activity, we have revaluated our strategy for ALLETE properties to include the possibility of a bulk sale of the entire portfolio which have consummated would likely be below book value. We will also continue to pursue sales of individual parcels overtime. Established in 1991, ALLETE Properties has been a successful business and contributed meaningfully to both earnings and cash flow through 2007. We have not made an acquisition of ALLETE Properties since 2002 and our strategy in recent years has been to thoughtfully exit over time as opportunities arose. Our objective is to unlock capital as we close out this historically successful legacy business and deploy proceeds into our strategy initiative. Al? Al Hodnik Thanks Steve. Earlier this morning we reported our 2015 financial results which reflect many successes for ALLETE during the year despite challenges on several fronts. Our reported earnings per share were $2.92 per share which includes profit from ALLETE Clean Energy’s construction and sale of a wind energy facility, the non-cash impairment charge at ALLETE Properties and acquisition transaction fees related to ALLETE’s energy infrastructure and related services businesses. Our full year results from our operating segments were as expected and Steve will go through the financial details in a moment. ALLETE’s value proposition remains intact and our 2015 results are a good example of how our operating businesses support ALLETE’s mission and how management deals with economic challenges and delivers on shareholder value. Our earnings guidance for 2016 remains at a range of between $3.10 to $3.40 per share and among other things reflects strong cost control efforts and increased cost recovery rider revenue in Minnesota Power, as well as growth at both ALLETE Clean Energy and U.S. Water. Before Steve goes through the earnings results, I would like to highlight several accomplishments from 2015. I believe the tremendous progress we have made on our strategy is clearly positioning ALLETE for continued growth through the end of the decade and beyond. ALLETE’s unique family of businesses is committed to service and reliability as we thoughtfully expand our significant renewable energy platform for answering the nation’s call to transform its energy and water sectors. ALLETE is well positioned to capitalize on an emerging environmental landscape that will not only require cleaner energy sources, but will also plays even greater emphasis on energy and water conservation to meet changing societal expectation. First, I’ll highlight several accomplishments from our regulated operations and additional efforts towards positioning our energy services businesses for the future. If you recall back in 2012, a severe rainstorm caused significant damage to Thomson Hydro, Minnesota Power’s largest hydro generation station. We are pleased that the Thomson Hydro Generating Station came back to full production in the fourth quarter of 2015, after more than 3 years and $90 million of restoration in repair work. This facility provides approximately 70 megawatts of carbon-free generation to our system. Minnesota Power recently completed the mercury emissions reduction project at Boswell Unit 4 which completes the compliance at our largest generating unit. There were also significant advancements during the year with the great northern transmission line, the proposed 220 mile, 500 kV line that will deliver hydro-electric generated electricity from Manitoba to Minnesota Power. During 2015, the Minnesota Public Utilities Commission determined the certificate of need and the route permit application were complete. Minnesota Power anticipates final route in presidential permit approval this spring. Great Northern Transmission Line construction is expected to begin in [Ernest] [ph] in 2017, with completion scheduled for 2020. We recently received commission approval to proceed with a 10 megawatts solar installation which will be built at Camp Ripley, Minnesota’s primary national-guard base near Little Falls on the southwestern edge of Minnesota Power’s service territory. The $30 million project will help Minnesota Power to achieve about one-third of its requirements under the state’s solar energy standard. Construction of the solar array is expected to begin in May, and continue to December with the goal to be producing solar power by November of this year. This creative partnership is a latest example of how Minnesota Power is achieving and advancing its Energy Forward strategy. Energy Forward balances stewardship, reliability, and affordability while maintaining fuel diversity within a generation portfolio that by the early 2020s will be comprised of one-third renewable, one-third natural gas, and one-third coal. All of these construction projects I just mentioned qualify for current cost recovery treatment which has provided as rate recovery outside of a general rate case proceeding. Related to our regulated businesses, on the industrial customer front, Minnesota Power’s taconite customers had a year of challenges to say the least. While there is no lack of domestic steel demand, challenges continue due to high levels of steel dumping into the United States. Minnesota Power’s customers nominated at approximately 80% of their capacity for the first four months of 2016. We continue to work closely with these customers on this and other issues, while we monitor developments with their production levels as we move forward into 2016. As you know, Minnesota Power also serves over a dozen wholesale customers. In September, we reported that electric contracts with 14 municipal customers were successfully amended to extend contract terms through December 31 2024. ALLETE Clean Energy expanded its renewable energy footprint in presence in 2015. During 2015 ACE acquired the 97.5 megawatt Chanarambie-Viking wind generation facility in Southern Minnesota, and they also acquired the 101 megawatt Armenia Mountain wind energy facility in Pennsylvania. ACE currently owns and operates approximately 535 megawatts of wind generating capability across the United States. In addition to owning and operating renewable energy facilities, in late 2014, we announced that ACE obtained the rights to develop and construct a 107 megawatt wind facility for Montana-Dakota Utilities. Earlier this year, we reported that Thunder Spirit was completed as planned at the end of 2015. We are proud of ALLETE Clean Energy’s accomplishments including adding this build-owned-transfer capability to its playbook. And we are excited about its prospects to leverage the cleaner energy future before us. Last but certainly not least, ALLETE acquired U.S. Water Services in early 2015. U.S. Water is a leader in integrated water management to growing number of industrial customers throughout the United States. With societal expectations rising around water quality, conservation, scarcity and reuse, we believe U.S. Water is well positioned to grow while addressing these interests. Financially and operationally, ALLETE had a very successful year even with the headwinds coming at some of our nation’s largest industries. ALLETE’s businesses posted financial result as expected and we made significant strides in executing our strategic plans. I will make some comments about our outlook for 2016 and beyond, but I will first ask Steve to go through the financial details. Steve? Steve DeVinck Thanks Al. For the year, ALLETE reported earnings of $2.92 per share on net income of $141.1 million versus earnings of $2.90 per share on net income of $124.8 million in 2014. Included in 2015 results are $20.4 million or $0.42 per share profit on the construction and sale of the Wind Energy facility by ALLETE Clean Energy, a $22.3 million or $0.46 per share non-cash impairment charge at ALLETE Properties; and $4.8 million or $0.10 per share of acquisition transaction fees related to ALLETE’s energy infrastructure and related services businesses. Earnings in 2014 included $1.4 million or $0.03 per share in acquisition transaction fees and a $2.5 million or $0.06 per share charge associated with an environmental protection agency settlement. ALLETE’s results are within its November 2015 earnings guidance range of $3.35 to $3.50 per share, which did not include impacts of the impairment charge or acquisition transaction fees. ALLETE also met its original December 2014 guidance of $3 to $3.20 per share, which did not include the impacts of the impairment charge, acquisition transaction fees or profit on the construction sale of the Wind Energy facility. Earnings from ALLETE’s regulated operation segment, which includes Minnesota Power, Superior Water Light and Power and the company’s investment in the American Transmission Company recorded net income of $131.6 million, an increase of $8.6 million over 2014. Earnings increased primarily due to higher cost recovery rider revenue, production tax credits, and power marketing sales, as well as lower operating and maintenance expenses. These increases were partially offset by lower industrial sales and higher depreciation interest and property tax expense. In addition, Minnesota Power recorded a reserve in 2015 for estimated refunds of $1.6 million after tax related to MISO return on equity compliance of which $900,000 was attributable to prior years. Our equity earnings in ATC in 2015 also reflected a $3 million after tax charge for reserves related to the same complaint of which $1.4 million after tax was attributable to prior years. Operating revenue from the regulated operation segment decreased $12.3 million or 1% from 2014 primarily due to lower field cost recoveries and gas sales, partially offset by higher cost recovery rider revenue, total kilowatt hour sales, as well as FERC pro forma based rate increases. Fuel cost recoveries decreased $37.1 million due to lower fuel and purchase power cost attributable to our retail and municipal customers. Revenue from gas sales at Superior Water Light and Power decreased $11 million as a result of the unseasonably cold weather in 2014 and warmer than average 2015. Heating degree were approximately 16% lower in 2015 compared to 2014. Cost recovery rider revenue increased $17.8 million primarily due to the completion of our 205 megawatt addition to our Bison Wind Energy Centre and CapEx 2020 projects, as well as higher capital investment balances for the Boswell Unit 4 environmental upgrade. Revenue increased $14.7 million due to a 3.1% increase in total kilowatt-hour sales. Sales to other power suppliers increased 48.4% mostly due to the commencement of the Minnkota Power sales agreement in June of 2014. Sales to our residential and municipal customers were lower due to the decline in heating degree days previously mentioned, and sales to our industrial customers decreased 11.4% primarily due to reduced taconite production. Revenue from our regulated customers increased $6.9 million primarily due to additional renewable, environmental, and other investments. On the expense side, transmission services increased $8.5 million or 19% from 2014, primarily due to higher MISO related expenses. Cost of sales decreased $9.4 million from 2014 due to the previously mentioned lower gas sales at Superior Water Light and Power. Operating and maintenance expense decreased $11.2 million or 5% from 2014, due to cost reduction efforts and $4.2 million charge in 2014, related to the EPA consent decree settlement. Cost reduction efforts resulted in lower wage, vehicle fleet, and miscellaneous employee expenses. These reductions were partially offset by no increases for the operation and maintenance of the 205 megawatt addition at our Bison Wind Energy Center that went into service at the end of last year. Depreciation and amortization expense increased $17.1 million or 14% from 2014, primarily due to additional property, plant and equipment and service. Taxes other than income taxes increased $4.3 million or 10% from 2014, primarily due to higher property tax expenses resulting from higher taxable plant and rates. Interest expense increased $4.7 million or 10% primarily due to higher average long term debt balances. Our equity earnings in ATC decreased $3.3 million or 17% from 2014. As we previously mentioned, our equity earnings in ATC were impacted by a $5.2 million charge, $3 million after-tax, the reserves related to the MISO return on equity compliance. Other income decreased $4.4 million from 2014, primarily due to lower AFUDC-Equity. Income tax expense decreased $14.6 million or 37% from 2014, primarily due to increased production tax credits as a result of the previously mentioned 205 megawatt addition to our Bison Wind Energy Center. Before I move on from the regulated businesses, I want to emphasize that we remain committed to cost containment at Minnesota Power. Despite known operating and maintenance expense increases for the 205 megawatt addition at our Bison facility, I am pleased that regulated operations, operating and maintenance expense is lower than 2014. We are reducing cost at Minnesota Power to reduce rate increases for our customers, improve our return on equity overtime, and manage through the impact of temporary cyclicality facing our customers in taconite mine. ALLETE’s energy infrastructure and related services businesses which include ALLETE Clean Energy, and U.S. Water Services, recorded net income of $29.9 million and $900,000 respectively. Earnings at ALLETE Clean Energy, increased $26.6 million over the last year due to higher earnings from its growing portfolio of Wind Energy facilities and a $24.4 million in profit earned on the construction and sale of the Wind Energy Facility. Operating revenue increased $228.9 million from 2014, with $197.7 million coming from the sale of the wind facility. Acquisitions in late 2014 and during 2015 also contributed to the year-over-year increase. U.S. Water acquired by ALLETE on February 10th of last year, is a leader in integrated water management to a growing number of industrial and commercial customers throughout the United States. U.S. Water Services had net income of $900,000 on revenue of a $119.8 million for the period February 10, 2015, through December 31, 2015. Earnings included $2.2 million of after-tax expense related to purchase accounting for inventories and sales backlog. The total impact of this purchase accounting adjustment is $2.5 million after-tax and is expected to be fully recognized by the first quarter of 2016. The corporate and other segment which includes BNI Energy, ALLETE Properties, and other miscellaneous corporate income and expense, posted a net loss of $21.3 million compared to a net loss of $1.5 million in 2014. The net loss for 2015,included the $22.3 million after-tax impairment charge at ALLETE Properties, and the $3 million after-tax expense for acquisition cost for the acquisition of U.S. Water Services. Earnings per share for 2015,were diluted by $0.36 due to an increase in weighted average shares outstanding. Our effective tax rate in 2015,was 15.2% compared to 22.6% in 2014. The decrease was mostly due to increased production tax credits resulting from the addition at our Bison Wind facility. We anticipate the effective tax rate for 2016, will be approximately 20%. ALLETE’s financial position continues to be solid, driven primarily by higher net income in non-cash expense. Cash from operating activities increased $70.3 million in 2015, to a total of $340.1 million. Our debt-to-capital ratio at year end was 47%. As Al, mentioned, ALLETE’s 2016 earnings guidance initiated last December includes a range of $3.10 to $3.40 per share. I would direct you to the 8-K filed last December for more details and key assumptions as part of our earnings guidance. Al? Al Hodnik Thank you for the financial update, Steve. ALLETE is a growing energy company that provides sustainable energy solutions through initiatives that are regulated utility businesses and at our complimentary energy infrastructure and related services businesses. I will highlight several areas for you along with some of our expectations for 2016, at our regulated businesses, Minnesota Power, will continue to execute its energy forward initiatives and pursue customer growth opportunities. Construction on the Great Northern Transmission line is ready to begin next year, and will provided investment and growth opportunities through the end of the decade. We feel that our energy forward actions have positioned us very well for the CPP, and other regulations. But like many other utilities, we harbor some concerns about ensuring we receive credit for early action taken to the benefit of all stakeholders. As well as the consequential nature of this regulation as it relates to reliability and affordability. While the CPP was stayed last week in a decision by the U.S. Supreme Court, we continue to work with stakeholders in shaping Minnesota’s CPP state implementation plan, continue to monitor its legal status and are taking necessary and prudent action to protect the value of our investments. We worked hard to reduce cost at Minnesota Power, and we have made significant progress. We have thoughtfully made workforce reductions with the elimination of approximately 100 position or 8% in 2015. We are pleased that the overwhelming majority of these reductions are made through coal fleet and other forms of attrition. We have also recently filed a proposal to implement Minnesota’s Energy-Intensive Trade-Exposed or EITE legislation signed into law by Governor Dayton. The EITE by design would allow for more competitive rates for large industrial customers. Last week the Minnesota Public Utilities Commission gave the EITE a fair hearing but rejected the petition without prejudice. The commission in taking the action they did, indicated they require more cost benefit information before they could make a final determination. Minnesota Power intends to meet once again with all stakeholders before determining next steps with EITE. In addition, Minnesota Power filed a depreciation life extension request, fully consistent with the environmental upgrades completed at our Boswell generating facility. If approved, this request would share some of the benefits immediately with customers. As I mentioned earlier, our Taconite customers nominated 80% capacity level for the first four months of the year. Nominations will occur in March, for the May to August time period, and in August, for the final four months of 2016. I should say that some of the idling reflected in these lower production levels could provide opportunities that have long, positive effects on taconite production here in northeastern Minnesota. To be specific, Cliffs Natural Resources has publicly shared its plan to retool its United Taconite plant in to produce Eveleth, to produce a fully fluxed taconite pellet. That new product will replace a flux pellet now made at Cliffs Empire operation in Michigan, which is scheduled to shutdown at the end of 2016. On the new customer scene, Essar’s last public update indicated it will achieve full production capability in 2016. As you will recall, the Essar facility will result in approximately 110 megawatts of new load for Minnesota Power, once it reaches full production levels. So the project has had its share of financing and market challenges since it was announced several years ago. We believe this opportunity for additional new load remains intact and operational startup is simply a matter of “when” and not “if”. To date, Essar has invested in excess of $1 billion in this facility which sits on the substantial, and very high quality ore body in Northeastern Minnesota. We do not anticipate any meaningful sales related to the Essar facility in 2016. PolyMet is anticipating the record of decision on its environmental impact state adequacy from the State of Minnesota in February, and action on applicable permits will follow. Construction could commence late this year, and Minnesota Power could begin to supply between 45 and 50 megawatts of new load to a 10year power supply contract that would begin upon start up of mining operation. ALLETE Clean Energy is positioned for earnings growth in 2016, as a result of the wind energy facilities it acquired during 2015. ACE will continue to target acquisitions of existing facilities which have long term power sales agreements in place. U.S. Water will further compliment our core regulated operation, balance exposure to our Utilities industrial customers, and provide potential long term earnings growth. 2015 marked a productive year of post-acquisition integration efforts, as well as a tuck-in acquisition in the southeastern United States. This, as U.S. Water continues its growth strategy, now, as part of the ALLETE family of businesses. Water and energy are intricately linked and attention to this nexus is increasing. Just like energy, we believe regulation and societal expectation will increasingly drive water conservation and that those macro factors along with opportunities for improved profitability will drive a growing emphasis on the efficient use of both water and energy. All of us at ALLETE are excited about our prospects going forward and we look forward to delivering another year of earnings growth. Our Board is confident in our direction, and recently voted to increase the dividend on our common stock. This is the sixth consecutive year we have had raised our dividend, and ALLETE has paid dividends without interruption since 1948. Thank you for your confidence and your investment with us. At this time, I’ll ask the Operator to open up the line for your questions. Question-and-Answer Session Operator [Operator Instructions] And our first question comes from the line of Paul Ridzon from KeyBanc. Your line is open. Paul Ridzon As you talked to your customers with steel exposure, kind of what’s their tone, are we bouncing on the bottom, are we starting to see some potential upside here, or is it just all in the hands of trade commission? Al Hodnik No, I think the sense is that, we’re bouncing off the bottom, at this point in time there are some green shoots beginning to appear, the ITC and some of the trade action that’s already been taken certainly back in Q4 of last year the sort of fuel consumption, some sort of imports within that 35% range, they’re trending down now and heading hopefully below 30% or heading in the right direction outlaid. There’s certainly more work to be done on some of these ITC sort of proceedings that are going on. We expect to hear more about that. I was also pleased to see that Governor Dayton from Minnesota has stepped up with other Governors, the Governors conference, and a dozen or so of the Governors have had conversation about spending more time with President Obama, on sort of additional levels of protection that might be able to be put into place. As you recall President Reagan and President Bush, impose section 201 of the 1974 Trade Agreement, and shutdown steel dumping altogether. And so we continue to push for that Chief of Staff, McDonough, President Obama, Chief of Staff was in Minnesota in December. I participated in that as there are number of steel company executives to express our concerns about steel dumping and so. Overall, I’m feeling more confident Paul, that we’re making progress on the steel dumping side, and that production here in the U.S. on the iron ore side can then follow. There’s certainly no lack of steel demand in the Great Lakes, as you know auto production is strong at this point in time, other durable goods production is pretty strong as well too. So, U.S. domestic production of steel was strong and we just need to end the steel dumping, and I think its heading in the right direction. Paul Ridzon Thank you. And Steve, can you review your commentary on O&M at Minnesota Power? Steve DeVinck Sure, Paul. I will. We remain committed to cost containment at Minnesota Power, to reduce rate increases for our customers, improve our return on equity overtime, and manage the impact of temporary cyclicality facing our customers on the taconite mining. With our 2016 guidance, we projected 2016 regulated operation and maintenance expense to be approximately 5% to 10%, less than 2014. This despite no increases for the operation and maintenance of these addition to our Bison Wind Energy facility. With respect to 2015, it is approximately $5 million to $11 million or 5% less than 2014, approximately $4 million of that is the charge that we had in 2014 for the settlement of an EPA. Paul Ridzon Okay, that’s the part I missed, that’s the part I missed, Steve, thanks. And given how successful you’ve been and how aggressive you continue to be, what’s your outlook on potential for Rate Cases or Rate Case? Steve DeVinck Yeah, our strategy Paul, as you know has been to improve Minnesota Power’s return on equity overtime through expense reductions and more clarity on load growth. Certainly, we made progress on the expense reductions including the workforce reduction Al, previously discussed. Of course, as we talked about consistent with our energy forward strategy, we’re seeking use for life extension at our Boswell facility, consistent with the remaining use for life of the extensive environmental upgrades that we have completed. This annual benefit is anticipated to be approximately $20 million, and reduced depreciation expense of which approximately one third would be returned to customers through the environmental cost recovery rider. We are evaluating the six months extension requested by the Department of Commerce, yesterday. We are also monitoring developments with our industrial customers to better understand future operation expectations. Nominations from our larger power customers are due March 1, as Al, mentioned, for May through August, and we expect to have more information on our talks about general Rate Case when we release earnings for the first quarter of 2016. Paul Ridzon Okay, thank you very much and I guess I’ll see you in a couple weeks. Al Hodnik Thanks, Paul. See you in New York. Paul Ridzon Thank you. Operator Thank you. Our next call comes from Brian Russo from Ladenburg Thalmann. Your line is open. Brian Russo Hi, good morning. Just what is the updated net book value — depreciated book value on the floor properties following the impairment? Steve DeVinck Approximately, $50 million. Brian Russo Okay. And what changed from a year ago? What triggered the impairment and is there something pending in terms of a bulk sale, which triggered this impairment? Al Hodnik The impairment was really due to in response to market conditions and other recent transaction activity, where we reevaluate our strategy. This revised strategy incorporates the possibility of a bulk sale for the entire portfolio which if consummated market indicators point to us with that will likely be in sales proceeds below book value. And we’ll continue to pursue sales of individual properties of course overtime. At this time we do not have affirmed sale of ALLETE properties. We expect that as we adjust our selling prices to better reflect market, the sales activity could pick up. As we stated, our objective is to unlock capital as we close out this successful legacy business and deploy the proceeds and our strategic initiatives. Brian Russo Okay, understood. And on the Boswell depreciation study, did I hear you correctly, the Department of Commerce requested a six month extension? Al Hodnik Yes, they did that yesterday. It was requested and granted. Brian Russo Okay. So, requested and granted, got it. Okay, so one of the six months on that. Just remind us what’s assumed in your guidance in terms of demand nominations to the 8% through the first four months or 80% for the entire year? Steve DeVinck So the midpoint of our guidance range, our guidance range is 310 to 340, assumes about 35 million tons of taconite production. And remember that in Northern Minnesota there is at capacities about 41 million tons. Brian Russo Okay, got it. And then you mentioned earlier Essar has publically stated that they assume full operation at 2016, however you guys have assumed no sales to Essar in 2016, are you just being conservative or there is something else that we should be aware of? Al Hodnik We’re just being conservative at this point. The — as I said to you many times and others that the start up of large taconite facilities are — it’s not sort of turn the switch on, and it’s110 megawatts in this case. So there’s a start up period, obviously they’ve had some construction fits and starts too as well. So we just decided to be conservative in 2016 with it and they said they’ve got a $1 billion investment at this stage of the game, and in my mind in our minds at least it’s not a matter of “if” it’s a matter of “when”. Brian Russo Okay. And then lastly, given the challenges that the solar industry is facing now, do you see ALLETE Clean Energy as becoming even more opportunistic as you were in 2015 in pursuing acquisitions? Al Hodnik Well, ALLETE Clean Energy is not going to continue to pursue acquisitions that make sense along all forms of the renewable space, the wind, and solar, and hydro, even clean sort of natural gas projects that come up. We still think cleaner energy forms are involved, the CPP even if it stay, certainly its base is really as cleaner energy forms as well. And so, we’re going to continue to look, they’re going to continue to look. They certainly have a deal flow and a pipeline of opportunities. But we’re going to be very disciplined as we have been and look for those that really provides best opportunities for shareholder value for ALLETE, those that come complete with PPAs, with off takers and credit worthy partners. Brian Russo Okay, thank you. Operator Thank you. Our next question comes from the line of Jay Dobson from Wunderlich. Your line is open. Jay Dobson Steve, earned ROE for 2015 at the regulated operations was? Steve DeVinck Minnesota Power’s total regulated return activity was approximately 8.5% in 2015. We estimate that with full taconite production return on equity would have been approximately 9%. I mean you might be interested about our views on 2016. The midpoint of our 2016 earnings guidance range we estimate Minnesota Power’s ROE would be in the mid-to-high 8% range. We estimate that with full taconite production return on equity would have been approximately 9%. And just a reminder, this does not include any impact from Essar or PolyMet. Jay Dobson Got you. That’s great. And then to the O&M, just for clarity, you said 5% to 10% when you gave guidance lower than 2014, but you got 5% in 2015. So the math isn’t going to be perfect. Is it fair to assume 2016 now relative to 2015, this sort of zeroed 4% to 5% reduction. Steve DeVinck Yes. That is fair. We did better in 2015 than we originally anticipated. So we are happy about that, but your math is probably fairly correct. Jay Dobson Great. And Steve was the real estate drag in 2015 and excluding of course the impairment. Steve DeVinck Yes, thank you. Excluding the impairment ALLETE Properties lost about $1 million. Jay Dobson Great. And then two sort of detailed questions. The purchase accounting impact that U.S Water you sighted is $2.5 million. That was the full impact in 2015. I am stating as the statement, but it’s a question and that’s a pre-tax number? Al Hodnik That is an after tax number and that’s the impact for the full year? Jay Dobson That is. So there will be that little stub period from January 01, 2016 to February 09, 2016 and then it will be exhausted. Al Hodnik Correct. Jay Dobson Great. And then the tax rate 15% roughly in 2015, 20% in ’16. What PTCs are you assuming in the 20% and I only ask that because you said the ’15 was sort of lower than expected, because you had a higher than expected PTCs. Al Hodnik No. I don’t know that it was lower than expected. We had higher PTCs from last year, production tax credits. 20%, it will go up to about 20% in 2016, primarily just due to higher pretax – a higher assumption of higher pretax income. Production tax credits in 2016 and 2015 are probably going to comparable since we had all of our Bison Wind facility in service at the end of 2014. Jay Dobson And then last one. As you think about sort of the acquisitions for U.S. Water and for ALLETE Clean Energy, maybe just talk about sort of what you expect out of acquisitions. Sort of vis-à-vis, I’m just measuring it sort of brutally if you will versus the U.S. Water, which was sort of a big addition, but not a lot of earnings. Steve DeVinck Well, we haven’t really changed our view on size of transaction at ACE. So our size of transaction is $50 million to $150 million plus or minus in that range, but we’d continue to try to pursue it. We had some smaller acquisitions at ACE of course but that’s kind of our focus and as I expressed earlier these broad range of renewable’s are still on the table, so we are not signally looking at Wind in that case. With respect to the U.S. Water tuck-ins if you will, those are likely to be smaller in nature sort of in the $5 million to $50 million range. As we think about our strategic acquisition there, there is a number of factors that come into the strategy in terms of geography and where we want U.S. Water to play and then those opportunities might present themselves. So that’s kind of the range. Both companies have a decent sort of deal flow with strategy to acquire. We also hope on the U.S. Water side accordance, we’d expect organic growth as you know. I think in excess of energy and water, it’s very important and in growing the final expectations are growing and so we just see greater demand for that also. And so organic growth is the part of U.S. Waters go forward strategy as well. Jay Dobson No, that’s great. And then actually just one last question on the Boswell proceeding. The delay for initial comments to August 16, what’s behind that? I mean I recall there was a January date which was extended to February, actually to today and then late yesterday, they extend to August 16. Is it work flow? What sort of driving that? Steve DeVinck Well, we haven’t had any direct conversation with the Department of Commerce regarding that, but I suspect there is a workflow and demand on resources issue down there with the Public Utilities Commission and also with the Department of Commerce. So there is of course a lot of work going on in a number of utilities with projects and with the filings. As you know with regards to Minnesota and what Minnesota is up to on energy policy. So I think it’s largely around sort of demands and resources basically and that would be the basis for their extension. Jay Dobson Got you. And we sort of put that together with EITE and rejecting – although rejected without prejudice and now this delay understanding in response to an earlier question, you indicated you will have more commentary and update on sort of outlook for rate case in 2016 this year – on the first quarter call. How do you think about those two? Obviously, both could be considered context of a broader rate case and at least as an outsider, it looks like on both issues for workflow or whatever the commission sort of kick in the can down the road. Al Hodnik Well, as I said with respect to EITE in the legislation that the legislature passed and the governor signed, we felt we got a fair hearing from the Minnesota Public Utilities Commission, almost an 8-hour in length hearings. One of longer hearings that I recall they were very deliberative. There were many good questions that were raised around the EITE. And in the last analysis, since sort of rejecting that petition unanimously, but without prejudice. That’s an important distinction. They more or less want us to go back and identify additional cost benefit relative to the EITE. They provided many good examples of areas of interest of theirs at least. And so we are going to go back with our stakeholders and work with them on that and draw some conclusions as to how we want to approach the EITE on going forward. Could EITE and depreciation and all that end up in the rate case? I suppose it could, but as Steve said earlier, we have a strategy rate now that really depends on cost reduction in ROE improvement in the near term. It also sort of expecting load growth to materialize and we are watching that very closely because lastly taconite nominations and so all of that kind of rules together. But to the extent, could it all fold in together? It certainly could. Is that what the commission and the DoC are necessarily driving towards? I don’t know that I could say that. Jay Dobson That’s great, Al. Thanks for the insight, Steve. Thank you. Operator Thank you. Our next question comes from the line of Paul Ridzon from KeyBanc. Your line is open. Paul Ridzon Just a follow up. You are beginning of the call you talked about some gives and takes and came back with around 306 ongoing number, wasn’t it about $0.05 of FERC’s reserves that you took out of period? Steve DeVinck Yes, from prior year. That’s probably about what it was probably about a nickel related to prior years. Paul Ridzon So 311 is probably another way at looking at ongoing earnings? Steve DeVinck That’d be another way of looking at it. Yes. Paul Ridzon Okay. Thanks to clarify. Thank you. Operator Thank you. And there is no further questions in queue. I’d like to turn the conference back over to management for any closing remarks. Al Hodnik Well, thank you everyone for being with us and thanks for your confidence and investment with us again. Steve and I look forward to seeing many of you in March 3, in New York. And I certainly will be on the road throughout the year here sharing the ALLETE story. Thanks for spending time with us this morning. Operator Ladies and gentlemen, thank you for participating in today’s conference. This concludes the program. You may now disconnect. Everyone have a great day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com . Thank you!

Portland General Electric Co.’s (POR) CEO Jim Piro on Q4 2015 Results – Earnings Call Transcript

Operator Good morning, everyone, and welcome to Portland General Electric Company’s Fourth Quarter and Full Year 2015 Earnings Results Conference Call. Today is Friday, February 12, 2016. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period. [Operator Instructions] For opening remarks, I would like to turn the conference call over to Portland General Electric’s Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir. William Valach Thank you, Candice, and good morning to everyone. I’m pleased that you’re able to join us today. And before we begin our discussion this morning, I’d like to remind you that we have prepared a presentation to supplement our discussion today, which we’ll be referencing throughout the call. The slides are available on our website at portlandgeneral.com. Referring to slide two, I’d also like to make our customary statements regarding Portland General Electric’s written and oral disclosures and commentary that there will be statements in this call that are not based on historical facts, and as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. And for a description of the factors that may occur that could cause such differences, the company requests that you read our most recent Form 10-K and Form 10-Qs. Portland General Electric’s fourth quarter and full year earnings release were released via our earnings press release and the 2015 annual Form 10-K before the market open today, and the release is available at our website at portlandgeneral.com. The company undertakes no obligation to update publicly any forward-looking statements whether as a result of new information, future events or otherwise, and this Safe Harbor statement should be incorporated as a part of any transcript of this call. As shown on slide three, leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Jim Piro will begin today’s presentation by providing updates on our operational performance, on Carty construction, our service area economy, and our integrated resource plan. Then, Jim Lobdell will provide more detail around the fourth quarter and full year results, our financing and liquidity, and discuss our outlook for 2016. Following these prepared remarks, we will open the lineup for your questions. And now, it’s my pleasure to turn the call over to Jim Piro. Jim Piro Thanks, Bill. Good morning and thank you for joining us. Welcome to Portland General Electric’s fourth quarter and full year 2015 earnings call. In 2015, we achieved several key objectives towards meeting our customers’ energy needs, and I’m pleased to share our results with you this morning. On today’s call, I’ll provide an overview of our financial results in 2015 and initiate 2016 earnings guidance, give you an update on our operating performance, provide an update on construction at Carty, summarize the economic conditions in our operating area, and outline the status of our 2016 integrated resource plan. Following my remarks, Jim Lobdell will provide details on the fourth quarter, and annual financial results, and end with our key assumptions supporting our outlook for 2016. So let’s begin. As presented on slide four, we recorded net income of $172 million or $2.04 per diluted share in 2015, compared with net income of a $175 million or $2.18 per diluted share in 2014. This decrease in earnings per share was largely due to a record warm winter that resulted in lower residential energy sales compounded by lower than budgeted hydro, wind and the associated lower production tax credits and higher replacement power costs. Management took prudent actions and through temporary operation and maintenance reductions offset approximately $0.09 per share of the financial impacts from weather and power costs. Now looking ahead for 2016, we are initiating full-year earnings guidance of $2.20 to $2.35 per diluted share, which reflects warmer than normal weather and lower wind production in January. Jim will provide more details later in the call. Now for an operational update on slide five, employees across the company did an excellent job in 2015 of improving efficiency, reducing costs and executing our business strategy to deliver value to our customers, shareholders, employees and the communities we serve. Our customer satisfaction remains very high in all segments. Residential business and key customers placed us in the top quartile or better for satisfaction, favorability and trust according to the latest survey results. Also our 2015 generating plant availability was excellent at an average of more than 92% across all of the resources PGE operates. 2015 was the warmest year on record in Oregon. The effects of weather impacted earnings by reducing energy deliveries to the residential sector, especially during the first quarter. As a result, management not only took actions to temporarily reduce operating and maintenance costs, but also worked diligently to ensure our delivery system and generating facilities operated extremely well. These actions were critical factors in helping to address the challenges posed by weather and higher power costs throughout the year. In 2015, we continue to demonstrate our leadership in delivering renewable energy and other programs to our customers. In addition to maintaining our standing as the number one renewable program in the nation, we won new awards, established a new offering for our customers and hit a new milestone. Our achievements included PGE’s two wholly-owned wind farms were recognized for being both safe and sustainable. Our newest wind farm Tucannon River is the first energy project in the nation to win the Envision sustainable infrastructure gold award from the Institute of Sustainable Infrastructure. This award was based on PGE’s contributions related to quality of life, leadership, resource allocation, the natural world and climate risk. Our other wind farm Biglow Canyon earned a Safety and Health Achievement Recognition Award, referred to as SHARP from the Oregon Occupational Safety & Health Division. This is the first time a wind project has qualified for SHARP certification in Oregon and only the second wind project in the United States. Also we enrolled – also we opened enrollment on a new renewable power option that enables customers to purchase output from a new 3-magawatt solar installation in the Willamette Valley, providing a way for more customers to support solar generation. And finally, our dispatchable standby generation program passed the 100 megawatt mark. This cost effective customer program helps meet regulatory requirements for non-spinning reserves. I’m very proud of these achievements. Now, turning to slide six for an update on our Carty Generating Station. On December 18, we declared Abeinsa, our engineering, procurement and construction contractor on Carty in default under multiple provisions of the Carty Construction agreement, and we terminated the agreement. As a part of the original construction agreement, PGE required Abeinsa to provide a performance bond to guarantee satisfactory completion of the project, in the event Abeinsa failed to fulfill their contractual obligations. The performance bond was provided by two sureties, Liberty Mutual Surety and Zurich North America for a $145.6 million. Following termination of the construction agreement, PGE in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015. Currently, we estimate the total capital expenditures for Carty will be in the range of $620 million to $655 million, including AFDC, and before considering any amounts received from the sureties under the performance bond. And we are targeting an in-service date in July of 2016. The prior Carty construction estimate of $514 million in capital costs, including AFDC was approved by the Oregon Public Utility Commission in the 2016 general rate case. We are currently in discussions with the Sureties regarding their obligations under the performance bond. And we believe they have an obligation under the performance bond to contribute funds towards completing the Carty project. In the event the total cost incurred by PGE for Carty less any amounts received from the sureties under the performance bond exceeds the OPUC approved amount of $514 million or the plant is delayed past July 31, 2016 the company would pursue one or more avenues for regulatory recovery. With regard to an update on the actual construction, all major components are on-site and are currently more than 700 construction workers on-site representing key contractors, including Day & Zimmerman, Sargent & Lundy, and Black & Veatch. Now to move to slide seven, where we provide a summary of the company’s current capital expenditure forecasts from 2016 to 2020. These amounts potentially could be augmented with incremental investment related to natural gas supply, system reliability and operational efficiencies that provide value to our customers. In addition, the graph does not include any potential capital projects from the outcome of our 2016 integrated resource planning process. We will continue to provide updates on our capital expenditure forecast in future earnings calls. Turning to slide eight, Oregon continues to exhibit several positive economic trends. First, unemployment in Oregon in December was 5.4% and approaching the range considered full-employment. Unemployment in our service area was even lower at 4.7% and compares favorably to the U.S. unemployment rate of 5%. Secondly, overall business expansion and new real estate investments continued in 2015. Investors have targeted Portland as a desirable West Coast location as evidenced by the large number of real estate transactions during the year and proposed new projects. With growth in both the number of local startups and in large Silicon Valley companies locating offices in the region, the Portland Metro area has become one of the fastest growing areas for high-tech employment. In addition, large high-tech industrial customers continue to expand their service area and contribute to weather-adjusted load growth of more than 2% in 2015 over 2014. This is net of approximately 1.5% in energy efficiency and excludes one large paper company who ceased operations in late 2015. Finally, Oregon was once again the number one state for in migration in 2015, according to a study from United Van Lines issued in January 2016 this is the third year in a row that Oregon has received the number one rating. PG’s average customer count continues to increase at approximately 1% year-over-year and looking forward, we expect weather-adjusted load growth in 2016 of 1%, net of approximately 1.5% in energy efficiency and excluding the one large paper company. On to slide nine. With regard to the integrated resource plan, we plan to file the 2016 IRP in the second half of 2016. The IRP assumes a 20-year planning horizon with an action plan for the period 2017 through 2021. The plan will address multiple issues including replacement of our Boardman Plant, which will cease operating on coal at the end of 2020, meeting the renewable portfolio standard of 20% by 2020, additional energy efficiency and demand side actions, additional capacity that needs to meet our customers, and several other topics. Now, I’d like to turn the call over to Jim Lobdell, who will go into more depth on our financial and operating results for 2015, and provide the assumptions for our 2016 earnings guidance. Jim? James Lobdell Thank you, Jim. Turning to slide 10. For the fourth quarter of 2015, we recorded a net income of $51 million or $0.57 per diluted share, compared to net income of $43 million or $0.55 per diluted share for the fourth quarter of 2014. This increase was primarily driven by the addition of Port Westward Unit 2 and the Tucannon River Wind Farm in customer prices, AFDC related to the construction of the Carty Generating plant, and a reduction to O&M in the fourth quarter of this year, offset by an increase in share count 2015, related to the final draw in June under the Equity Forward Sale Agreement. Also, targeted earnings for the fourth quarter 2015 were reduced by warm weather, which had a negative impact of $0.05 in comparison to normal. As shown on slide 11, for the full year 2015, we recorded net income of a $172 million or $2.04 per diluted share, compared with the $175 million or $2.18 per diluted share for 2014. This decrease was largely due to the warmest year on record in Oregon, resulting in lower residential energy sales, compounded by lower than planned hydro and wind conditions, resulting in higher replacement power costs, and lower than anticipated production tax credits, and an increase in share count due to the timing of the final draw under the Equity Forward Sale Agreement. These decreases were partially offset by earnings from two additional generating clients, placed in service, Carty AFDC and a strong effort to temporarily reduce O&M spending for the year. Moving onto slide 12. For the full year, total revenues decreased $2 million. This decrease in revenues was primarily due to a reduction in residential energy deliveries, in addition to lower wholesale and other revenues. These decreases were partially offset by a 1% increase in customer prices. Purchased power and fuel expense decreased $52 million year-over-year, driven by an 8% decline in the average variable power cost per megawatt hour. The decrease was largely driven by a 3% decrease in the average price of purchase power and the economic displacement of Boardman in 2015. Net variable power costs is reported for regulatory purposes were $3 million below the baseline of the power costs adjustment mechanism. However, when adjusting for a couple of one-time transactions which did not flow to the company’s income statement. In 2015, net variable power costs were $6 million above the baseline, reflecting lower wind and hydro generation, partially offset by optimization of the overall power supply portfolio. This compares to $7 million below in 2014. Moving on to slide 13, operating and maintenance costs totaled $507 million in 2015, $23 million higher than in 2014 and $13 million below the midpoint of our original 2015 guidance range of $510 million to $530 million. The higher costs in 2015 were driven primarily by the following increases, $9 million and costs related to the addition of the Port Westward Unit 2 and Tucannon River Wind Farm and $14 million in administrative and general costs including $5 million increase in information and technology expense and an increase of $3 million in non-labor and outside services expense. The reduction in O&M spending relative to our original guidance reflects the company’s commitment to attempt to offset reduced earnings from warm weather in the first quarter of 2015. Depreciation and amortization expense was at the midpoint of our guidance range and increased $4 million of $301 million in 2014 to $305 million in 2015. The increase was primarily driven by a $26 million increase expense and the capital additions offset by a $22 million reduction of the amortization of deferred regulatory liabilities from the Trojan spent fuel settlement and tax credits as they were refunded to customers in 2015. Interest expense increased $18 million in 2015 compared to 2014. This was driven primarily by a $9 million increase resulting from lower allowance for borrowed funds used during construction, combined with a $7 million increase in interest expense due to higher debt outstanding in 2015. Other income net decreased $16 million year-over-year as a result of the $16 million decrease and the allowance for equity funds used during construction as the Tucannon River Wind Farm and Post Westward Unit 2 were put into service in December 2014. Lastly, income tax has decreased $16 million year-over-year, largely due to a $14 million increase in production tax credit and the addition of the Tucannon River Wind Farm. The company’s effective tax rate decreased to 20.7% from 26% in 2014. We did not take bonus depreciation in 2015, and we have not taken it since 2010, because we have favored using production tax credits and other state tax credits with expiration dates over using bonus depreciation. Given the extension of the bonus depreciation through 2019, we will continue to assess our approach each year. On to slide 14, we continue to maintain a solid balance sheet, including strong liquidity and investment grade credit ratings. As of December 31, 2015, we had $550 million in cash, available short-term credit and letter of credit capacity, $867 million of first mortgage bond issuance capacity and the common equity ratio of 50.5%. The company has a $500 million revolving credit facility to meet the company’s liquidity needs, which has a maturity date of November 2019. The company has additional letter of credit facilities totaling $160 million. In January of this year, PGE issued a $140 million of 2.51% Series First Mortgage Bonds, which were used to fund an early redemption of two outstanding Series First Mortgage Bonds. The company plans to potentially issue up to an additional an $160 million of long-term debt in 2016. Moving onto slide 15, on November 3, 2015, The Oregon Public Utility Commission issued an order that when combined with customer credits results in an overall increase in customer prices of approximately 0.7%. These prices were effective in two phases, a 2.5% decrease in the January 1, 2016, and a 3.3% increase when Carty comes into service, provided it happens by July 31, 2016. The changing customer prices will reflect a return on equity of 9.6%, a capital structure of 50% debt and 50% equity, a cost of capital of 7.51%, a rate base of $4.4 billion, and an annual revenue increase of $12 million. As shown on slide 16, we’re initiating full year 2016 earnings guidance of $2.20 to $2.35 per diluted share. This guidance is based on warmer than normal weather, and lower wind production in January 2016, which resulted in roughly an $0.08 impact on earnings. Additional assumptions include the following: retail delivery growth of approximately 1%, weather adjusted, and excluding one large paper company; average hydro conditions, wind generation based on five years of historic production or forecasted studies when historical data isn’t available; normal internal plant operations, operating and maintenance costs between $515 million and $535 million; depreciation and amortization expense between $315 million and $325 million; and the Carty Generating Station in service by July 2016, at approximately the OPUC authorized capital amount of $514 million. Back to you, Jim. Jim Piro Thanks. As we begin 2016, we are moving forward on initiatives that drive value for our customers and shareholders. Slide 17 displays our key objectives for 2016. First, maintain our high level of operational excellence with a focus on employee and public safety, meeting our operational and performance goals and meeting our financial performance targets. Second, bring Carty Generating Station into service, on or before July 31, 2016. And third work collaboratively, with all of our stakeholders, to prepare our 2016 integrated resource plan and its associated action plan, to meet our customer’s future energy needs, using resources that provide the best long-term balance of cost and risk. And now operator, we are ready for questions. Question-and-Answer Session Operator Thank you. [Operator Instructions] And our first question comes from Michael Weinstein of UBS. Your line is now open. Michael Weinstein Hi, good morning. Jim Piro Good morning, Michael. James Lobdell Good morning. Michael Weinstein Hey on the results for 2015, where you say that you have a temporary reduction O&M of about $0.09 I believe you said at the beginning of the call. Jim Piro Yes. Michael Weinstein Okay. So, why is that temporary and I’m guessing that since, it’s temporary does that $0.09 is now responsible for higher O&M in 2016 guidance. So, going forward in 2017, we would subtract that $0.09 out again to normalize? James Lobdell No, Mike, I wouldn’t do that. What we did in 2015 was to the extent that we could push off any particular activities and not impact safety and reliability or customer satisfaction, we took account for that, but I wouldn’t add that back into the following year, or just pick a point in time. We still need to assess or what needs to happen there. Jim Piro Yeah. In 2016, our O&M is in line with what was allowed in the general rate case and that’s for work that needs to be done on our system, to meet our reliability and customer service obligation. What we looked at in 2015, we’re delaying some types of work and it’s not something we can do permanently. Michael Weinstein Right. And also on the Carty project, is there any chance that you guys can finish the project before July right now or is it something you’re willing to talk about in terms of is the project ahead of schedule or is it exactly on schedule and any slippage might be a problem? Jim Piro Well, we have a schedule and it has us completing the project in July and we have some room, but everything is going to have to go perfect. We have to go through the startup, we have to get all the construction work completed. As I mentioned earlier, we’ve mobilized enough people on the site to do the work. Now, we have to see the productivity and we have to see everything go as we have planned. And so, we’re going to watch it pretty carefully. We’ll know a lot more at our next earnings call. But I would say everything is fully going at this point, and we’re moving and things are happening out at the site. Michael Weinstein At what point do you think you’ll finish negotiating with the surety providers to figure out exactly how much they are going to assume? Jim Piro That’s going to be a process. We do have a meeting scheduled in March, but that will be just the first step in the process with them. Michael Weinstein Okay. All right. Thank you very much. Operator Thank you. And our next question comes from Paul Ridzon of KeyBanc. Your line is now open. Paul Ridzon Good morning. How are you? Jim Piro Good morning. James Lobdell Good morning, Paul. Paul Ridzon Can you parse out the $0.08 headwind we’re facing? How much of that is wind and versus weather? James Lobdell Most of that is all weather, and about $0.02 of it represents wind. And then there’s the PTCs in there as well, which is about a $0.015. Paul Ridzon Okay. Just back to Mike’s question, so how much of the $0.09, how much was deferring versus actually just not doing, and then how much of that $0.09 is creeping into 2016? Jim Piro The O&M forecast that we have provided the range is to do the work we need to do in 2016. Things that we didn’t get done in 2015 or delayed are basically incorporated in our budget for 2016. So, we have a budget now. We have a work we have to get completed and I think we are aligned with our budget for this year. James Lobdell And that’s embedded in our guidance. Paul Ridzon Okay. And then just on history of Carty, $514 million was approved and now you’re looking $620 million or more. What kind of – what’s the delta there? James Lobdell [With cost] [ph] $140 million, we took the high-end versus the $514 million. So basically what we’ve got there is we have to remove liens that have been [perfected] [ph] associated with the site. We’ve got a lot of rework that needs to be done, cost to complete the construction, which is construction and start-up, site stabilization, there are delayed costs that can include productivity, AFUDC and contingency and other costs. Paul Ridzon You are successful in securing the full surety Carty will come in under budget? Jim Piro Well, I think it’ll come in pretty much at budget. I think the 514 included the contractor meeting the obligations under the agreement. So, our sense would be is if the sureties do what we think they’re responsible for doing, we would come in at our budget amount. Paul Ridzon Okay. Thank you very much. James Lobdell Thanks, Paul. Operator Thank you. And our next question comes from Chris Turnure of JPMorgan. Your line is now open. Jim Piro Good morning, Chris. Chris Turnure Good morning, guys. James Lobdell Good morning, Chris. Chris Turnure Could you give some more color on Carty? Just another question on that front. How do you plan on financing the incremental cash that you’re going to need to fund that this year? And have you had any conversations with the commission yet, and kind of walking them through what’s gone wrong throughout the process and to the degree that you kind of do about it even before late December? James Lobdell Well, the first part of the question is, how are we going to go about funding the incremental capital associated with the project. I think as we have mentioned previously, we’ve got plenty of capacity under our short-term [earnings] [ph] access to bank loans that we can provide in order to cover any incremental costs that we have to fund that we’re not getting from the sureties associated with the project. On the regulatory side… Jim Piro Yeah. I can cover that. We’ve been keeping the PUC informed throughout the process. We recently have been asked to provide an update on Carty through a public meeting. However, it hasn’t been scheduled yet. Probably, that meeting would happen sometime in March or April. Chris Turnure Okay. And have you disclosed how much, let’s say a one month delay in the project past July 31 would mean for EPS? James Lobdell No. We haven’t. Chris Turnure Okay. And then, my second question is just on the legislation now kind of making its way through the legislature over there. Can you give me some color on what do you think the chances of passage are, and then what that would mean for the next, let’s say five to seven years of capital deployment and renewable growth opportunities for you guys, because certainly in the long-term it would be a big benefit, but I am focused a little bit more on the near-term. Jim Piro Yeah. So let me give you an update on it, it’s called the Oregon Clean Electricity plan, it’s called H.B. 4036 is the actual bill number. It just passed out of the House Energy and Environmental Committee on a 6-4 vote. It will now go to the floor for a vote at the House level. Assuming if it passes there than it would move to the Senate Committee, and then work its way through the Senate. The bill essentially does two major things; number one, it eliminates coal in Oregon by 2030 and for us up to five years later for Colstrip up to 2035. And then it increases our renewable portfolio standard targets, mostly in the out year. So it’s a 50% standard by 2040. The interim targets are 27% in 2025 versus the current RPS standard of 25%. 35% by 2030, 45% by 2035 and 50% by 2040. So you can see from those new numbers, the bulk of the changes would be in the outer years, as we go to a 50% RPS standard. This will all be factored into our integrated resource plan as we work through the process in this case, because we wouldn’t want to go long generation as we think about a higher RPS standard. So, it’s all been factored into our planning at this point, but it is all dependent on that law passing the legislature and signed by the Governor. So, that’s kind of where it is. We have got support, a number of people are supporting the measure, and there is some opposition to the measure. So, we’ll just have to see how it plays out. Chris Turnure Great. That’s helpful. Thanks. Operator Thank you. And our next question comes from Brian Russo of Ladenburg Thalmann. Your line is now open. Brian Russo Hi, good morning. Jim Piro Good morning. Brian Russo Could you just remind us the amount of capacity you need to meet the 20% RPS in 2020, any backup capacity necessary and then, the number of megawatts you need to replace on Boardman? Jim Piro So, in 2020, the RPS standard goes another 5%. It’s probably a very similar to Tucannon River Wind Farm, it’s probably around 100 average megawatts. So, it’d be very similar to adding another Tucannon River Wind Farm. If you’re thinking about the size of that, that was about 267 megawatt of nameplate capacity. So, a lot of it will depend on capacity factor. So, that’s kind of what we’re looking at it. The timing of that still kind of up in the air. With the extension of the PTCs, we’ll have to evaluate when is the right timing for that unit, because we do have renewable energy credits that we can apply. And so, we’re looking at what’s the right timing of that, especially given the extension of the production tax credit. That will all be a topic of our integrated resource planning discussion. As it relates to Boardman, our piece of the capacity is about 520 megawatts, hydropower owns 10% of the project. And so, that is again being evaluated on what to – how we replace Boardman in the IRP. Obviously, I think, prior to H.B. 4036, I think our thinking was likely a natural gas prior plant would be that the type of thing we would do, and we would do and we will have to do an RFP like we did before, but as you know, we’ve said before, Carty has been designed as the two-unit site. So, it would be a very good site to look at the second unit there. But with a 50% RPS standard, we have to kind of consider the entire mix in the long-term trajectory and what’s the right kinds of resources we’re going to need. So, it’s not clear to me at this point, what we will do to replace Boardman, whether it will be more capacity in renewables or base load gas generation. So, that really is the topic of the IRP and we’re just now in the process of developing portfolios that we can look at to see what provides the best balance of cost and risk going forward. Brian Russo And would you need backup power for the – an additional wind farm? Jim Piro Yeah. As we look at the renewables, as you know, they are not firm energy, at least we haven’t found at this point that really correlate directly with our loads. So, it would be a wind farm, backed up by some type of capacity resource, either a simple cycle turbines or reciprocating engines like Port Westward Unit 2. Again, we have capacity needs. That’s something that’s been identified in the integrated resource plant as we look at what our loss of load probability study show us. And so, that is going to have to be addressed also. But our sense is, we’re going to need additional capacity as we go to a higher RPS standard. Brian Russo Okay. So, just back of the envelope $1,100 a KW for CCGT and maybe $1,500 a KW for wind, I know you talked in probably a $1 billion of potential spend, is that reasonable? Jim Piro Potentially, again, as you know, we have to go through an RFP. We have to ensure that we have the least cost, lowest risk projects to bring forward. As we’ve said before, we would always want to include our own self build options and I think we’ve demonstrated from the construction of Port Westward Unit 2 and Tucannon, that we can deliver those projects on time and on budget. So, we will want to provide our own projects. We have some sites that are very competitive sites, at least on the gas side, and we’ll continue to look for those wind farms, and wind projects that can meet our renewable standard. Brian Russo And when would you expect to get acknowledgement from the OPUC, and when would be RFP process start, and then finish? Jim Piro Probably in 2017, we expect the acknowledgement from the commission. James Lobdell We’ll file in the later part of this year. We would expect a position decision in early part of 2017. Then, we will go into an RFP process, where hopefully we’d know the decision by late 2018 and then, move forward from there. Brian Russo Okay. Great. And then, what are the regulatory options for recovery of the Carty costs above what’s in the general rate case? Jim Piro Well, there’s couple of things. First of all, it depends on what the number is. Obviously, if we’re above that, but only slightly, we’ll evaluate that, and we’ll have to understand the reasons for that. But, the way we would do that is through general rate case, and next subsequent rate case. At this point, we’re not planning on filing a 2017 general rate case, looking to 2018 as a potential. We will then file that case with what we think our prudent capital costs, and we will go through the process to support those costs. If the project is delayed beyond July 31, we will enter into discussions with the stakeholder groups to talk about options to recover the costs. A lot of it will be dependent on when that project will be going online, and we’ll determine what’s the best way to move that forward. We have options and – but a lot of it depends on when that project would come online. Brian Russo Okay. And then, I assume that midpoint of your guidance assumes a zero balance on the PCAM? James Lobdell Yes. Brian Russo And when was the net variable cost set in terms of gas prices or prevailing commodity prices? James Lobdell It was set in November, when we file our final update, which includes cost curves and all our contracts that we have in place. Usually, we’re about 95% hedged against our forward position. So, we’ve locked in those financial or physical contracts on gas as well as any electric purchase contracts. So we’re pretty balanced in November. So, than the variabilities we deal with are hydro, wind and plant availability. So those are things that we feel. The good news is that hydro is about normal this year. We’ve had a really good snowpack early on and we’ll have to see how it goes for the rest of the year, because that normal forecast does assumes normal precipitation for the rest of the cycle. So, we’ll watch that pretty carefully as we see a snowpack build hopefully. Brian Russo And what appears to be lower gas prices now versus I guess what was implied in November, are you able to optimize your generation fleet to kind of capture that spread, so to speak? James Lobdell Not necessarily. A lot of it will depend on what happens in markets in terms of opportunity, but our plans are committed to meet our retail load. And so, we’ve already locked in essentially the gas price for those plants to run and meet our retail load. There may be some opportunity, but probably the only real value is that, if for example, we have lower wind, a lower gas prices would lower our replacement cost instantly with hydro. But on the flipside, if we have a lot of hydro, low gas prices depressed the market price, so we don’t get as much value. So it has kind of pluses and minuses as we think about it. But right now, we’re hedged against where our loads and resources are. Brian Russo Okay. Thank you. Operator Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open. Jim Piro Hi, Michael. James Lobdell Hi, Michael. Michael Lapides Hey, guys. Congrats on a good year and a good start to 2016. Just curious, thinking about the RFP process and thinking about the IRP as well, does the State of Oregon need capacity or energy or does simply your service territory does and so one of the alternatives in all of this process could be simply increasing the amount of power that could be sent into the Greater Portland area from other parts of the state. The reason that’s, I’m kind of thinking through that is, there are – we’ve seen in other states over the years, Louisiana, Mississippi great example of this also in the desert Southwest, where merchant projects that were in a state like in Oregon or like Louisiana or Arizona, roundup getting bid into RFPs and sold at a price that was well below new build cost. Now, some of the ones in your state, they’re not really in downtown Portland, so there it have to be a transmission alternative, but I think that largely will depend on, is it a state need or is it a part of the state need for new capacity in energy? Jim Piro So, let me talk about that generally. In the last IRP, projects that were available or bid in, and they were not competitive with new generation, just because of higher heat rates and older units. So they were not successful. And to that extent, nothing has been built since then to my knowledge in the region in terms of new gas fire generation. James Lobdell And then, on top of that, you got several plants that will be taken out of the regional mix, but essentially are the – plants will be going away, Boardman will be going away in 2020, and what has been added to the market place has been mostly in variable energy resources… Jim Piro Under a contract. James Lobdell Yeah. Jim Piro Typically under contract. So, you think about Oregon, and maybe the region, I see has been more capacity deficit, our study show that. And there is just not capacity sitting on the sideline. On an energy basis, it’s a really kind of tough issue as we see all these renewables show up in the system. Obviously, what’s going on in California with the Duck Curve and all the solar energy down there, those are the things we’re looking at, but the strong to California is only so large. And so, we have to think about the reliability of that supply as well as the costs. So, those are things that we are evaluating in the IRP, but I would clearly say, there is a need for additional capacity in the region, especially as we add in more variable resources. Michael Lapides Got it, guys. Thanks. One follow-up, unrelated to that. You made some minor changes to your base CapEx forecast in today’s disclosure. Can you just kind of walk us through what drove those changes? James Lobdell Yeah. Effectively, it was just a shifting of dollars associated with our customer information, and meter data management project, and that was essentially it. Michael Lapides Meaning, moving stuff into 2016 from it, can you just like – which years went up, which years went down and what was the – and was that the main driver of that, when I think about 2016, 2017, 2018 or so? James Lobdell Well, the movement of dollars from 2017 to 2016. Michael Lapides Got it. Okay. So, you just moved up the project a little bit. James Lobdell Yes. Michael Lapides Got it. Thanks, guys. Much appreciate it. James Lobdell Thanks Mike. Operator Thank you. [Operator Instructions] And our next question comes from Paul Patterson of Glenrock. Your line is now open. Paul Patterson Good morning. Jim Piro Hi Paul. Paul Patterson Just on H.B. 4036, looks quite ambitious, and I haven’t checked. When it passed, I guess it was about yesterday. Were there amendments that addressed some of the issues that I guess are being brought up by the Oregon PUC? I guess, was there any big changes, or would those issues addressed or do you think that – I mean, it looks like it passed with a pretty good margin, I mean I’m just sort of wondering? Jim Piro Yeah. It passed to explore, I don’t recall if there is – I was talking to Dave yesterday, there weren’t any major amendments, and there might have been a few tweaks, but nothing that was material to way legislation would setup. I think the important thing to note is that it does still have the cost cap, and that’s currently in the legislation today. It also added another standard around reliability. So it has provided certain protections for our consumers that we think are adequate to address the concerns the commission has raised. Our evaluation looking at price impacts on consumers over the lifecycle is Bill, is somewhere in the 1.5% higher prices. So it’s not materially higher. As I said, the bill has passed, the House Committee, it’s going to the House floor for vote. It can then move to the Senate, where we could see potential other amendments, and we’ll have to see how that plays out in the coming weeks. Paul Patterson It looks like it’s on schedule for the House passage next week – early next week? Jim Piro That’s correct. And then, it goes to the Senate, Senate Business and Transportation Committee. Paul Patterson Okay. And is energy efficiency part of the RPS standard or is that separate? In other words, I mean, does energy, because I did notice this regional for state thing that was big pushing energy efficiency, is that part of getting to be the standard? Jim Piro No, because that just reduces our load energy efficiency. It just measures that. We don’t want to continue our commitment to energy efficiency. We use the Energy Trust of Oregon to determine what is the least cost, lowest risk energy efficiency and how to acquire that. We do a very detailed study in our IRP to determine what that is. And so, I don’t think that changes dramatically in this legislation. It just continues to support the need for energy efficiency, but it does not count against the RPS standard in a sense that it’s part of the – how we meet retail load. It would reduce retail load, but it doesn’t necessarily count as – against the percentages. Paul Patterson Okay. Excellent. And then, just in terms of obviously this CapEx forecast, we should expect that once this – we get more information on H.B. 4036 and your IRP, that – those numbers will probably be considerably higher, I would expect, correct? James Lobdell Yeah. I think the question we have to ask and we’ll be looking at this in the IRP is, given the shutdown of Boardman in this high RPS standard, what’s the right timing and quantity of renewables we need to add to the grid, kind of to get us to the 50%. Because you wouldn’t want to necessarily agitate base load gas generation, and then, find out that you have too much generation as you go to a 50% RPS. So we’re going to have to think very, very smartly about the right mix of resources and the trajectory to get to that 50% RPS, and the bill does allow us to may be pre-build ahead of the need if we can demonstrate that’s the cost effective thing to do. So that’s really the magic here in trying to figure this all out is, what’s the right timing of doing this in a way that provides the least cost, lowest risk for our customers. Paul Patterson Okay. Great. The rest of my questions have been answered. Thanks so much. James Lobdell Thank you. Jim Piro Thank you. Operator Thank you. And our next question comes from Michael Weinstein of UBS. You line is now open. Michael Weinstein Hey guys. A quick follow-up question. On the legislation, as a co-owner of Colstrip 3 and Colstrip 4, just wondering what do you see, how do you anticipate the disposition of that plan once coal by wires eliminate 2035 for it, under the legislation, what do you see happening with it? Jim Piro So, we’ve thought a lot about that. Obviously, our plan under this would be to recover all the capital costs and decommissioning costs through 2030 or 2035 depending on – the legislation allows us to keep the plan in customer prices through 2035. So, beyond that, the question is, what would we do with the plant. There is options we would consider obviously, if the plant continues to operate, it has value, we could either sell it in an auction, we could sell the power in the market. Those are two considerations as we look forward. And those are the things we’ll have to evaluate as we get closer to that period. And so, we don’t have any answer yet, but we have options. Michael Weinstein On minority owner. Jim Piro Yeah. We’re a 20% owner in Colstrip 3 and Colstrip 4. So, it’s not like we can decide to shut the project down. And so, we will look at that as we get closer to that timeframe, but those are the two options we would consider. Michael Weinstein Okay. I’m just wondering if there’s been any moves to try to push to sell to [indiscernible] just like they’re doing with Colstrip 1 and Colstrip 2? Jim Piro Well, yeah, I understand that. And… James Lobdell Yeah. Jim Piro In Washington, they have a prohibition from utilities buying coal output also. So, I know they’re working on their own issues around units 1, 2, 3, and 4. And we’ll have a lot to see when we get there. I think the landscape can change. Montana is a potential market. Obviously, there are other places that power could be sourced to. Yeah. Michael Weinstein Right. Okay. Thank you. Operator Thank you. And our next question comes from [indiscernible]. Your line is now open. Unidentified Analyst Hi, good morning. Jim Piro Good morning. James Lobdell Good morning. Unidentified Analyst Just a question on slide 14 regarding the financing. You guys have year marked about a $160 million of additional bonds you may issue. Is that currently embedded in the future testier that you have this year, and then in guidance? What’s the situation with the interest related to that? And what was the site, if you issue it or not? Jim Piro Yeah. Now, it is included in the guidance already. Unidentified Analyst It’s included in the rate case too. Jim Piro Including the rate case too. Unidentified Analyst Because I think, do we update the numbers for those bonds or? Jim Piro Updated for the bonds of … James Lobdell January. Jim Piro January, yeah. Unidentified Analyst Okay. Jim Piro Great thing. If you aligned up with the guidance that we have. Unidentified Analyst Okay. And then, just one follow-up question. Now, this is kind of an asset, I just want to make sure I understand it correctly. On the surety bonds, by when do you need to have some kind of resolution on those before you decide to take action at the commission? I mean, you can have the plant in service by your required service date, but when do you need to know about the recovery of the surety bonds before you go to the commission? Jim Piro Well, right now, our prices are based about on the $540 million, and that’s kind of the agreement we have, the next time we would address this in a subsequent general rate case. And so, we would obviously need to have that resolved by then, but if we’re looking at a 2018 general rate case, we’ve got sufficient time to address that. Again, our hope is that we will get full compensation for the cost exceedance, but that’s obviously something we have to work through with the sureties. Unidentified Analyst Okay. I appreciate it. Thank you and congratulations. Jim Piro Okay. Operator Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open. Michael Lapides Hey guys. Just a quick question on rate case timing again, meaning going forward. It doesn’t sound like you are going to do a lot of construction on stuff related to the RFO or RFP until the 2019 timeframe. Do you anticipate filing again between now and then? James Lobdell Yeah. Right now, our thinking is, 2018 general rate case, but a lot of that will depend on load growth, inflation, cost controls, just a number of factors that we look at. We clearly have not filed for a 2017 rate case and don’t anticipate doing that, absence something going on with Carty. So, we would likely look at 2018. We will make that decision till probably November of this year, when we finish our budget to be filed in February of 2017 for a 2018 general rate case, if we decided to do that. A lot of it will also depend on interest rates, what return on equities are doing. So, there are a whole bunch of factors will go into that decision. But right now, that’s kind of what we’re pointing towards, but we haven’t made a final decision. Michael Lapides Got it. So, you would file in 2017 for 2018, but that really wouldn’t incorporate many of the stuff coming out of the RFP process? James Lobdell Not at this point now. And to the extent there are renewable resources, we do have the tracking mechanism under the current RPS standard, that those can get track in directly when they go into service. So, we’d only be either capacity resources or something other type of thermal resources that would have to get, whether we require a general rate case. So, we could actually track in the renewables with the current standards we have and the mechanism we have. Michael Lapides Got it, guys. Thank you. Much appreciate it. James Lobdell Thank you. Operator Thank you. Jim Piro Okay. I think that’s the end of the calls. We appreciate your interest in Portland General Electric and invite you to join us when we report our first quarter 2016 results in late April. Thanks, again, and have a great day. Operator Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program, and you may all disconnect. Have a great day, everyone. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com . Thank you!

Portland General Electric Co. (POR) CEO James Piro on Q4 2015 Results – Earnings Call Transcript

Operator Good morning, everyone, and welcome to Portland General Electric Company’s Fourth Quarter and Full Year 2015 Earnings Results Conference Call. Today is Friday, February 12, 2016. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period. [Operator Instructions] For opening remarks, I would like to turn the conference call over to Portland General Electric’s Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir. William Valach Thank you, Candice, and good morning to everyone. I’m pleased that you’re able to join us today. And before we begin our discussion this morning, I’d like to remind you that we have prepared a presentation to supplement our discussion today, which we’ll be referencing throughout the call. The slides are available on our website at portlandgeneral.com. Referring to slide two, I’d also like to make our customary statements regarding Portland General Electric’s written and oral disclosures and commentary that there will be statements in this call that are not based on historical facts, and as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. And for a description of the factors that may occur that could cause such differences, the company requests that you read our most recent Form 10-K and Form 10-Qs. Portland General Electric’s fourth quarter and full year earnings release were released via our earnings press release and the 2015 annual Form 10-K before the market open today, and the release is available at our website at portlandgeneral.com. The company undertakes no obligation to update publicly any forward-looking statements whether as a result of new information, future events or otherwise, and this Safe Harbor statement should be incorporated as a part of any transcript of this call. As shown on slide three, leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Jim Piro will begin today’s presentation by providing updates on our operational performance, on Carty construction, our service area economy, and our integrated resource plan. Then, Jim Lobdell will provide more detail around the fourth quarter and full year results, our financing and liquidity, and discuss our outlook for 2016. Following these prepared remarks, we will open the lineup for your questions. And now, it’s my pleasure to turn the call over to Jim Piro. James Piro Thanks, Bill. Good morning and thank you for joining us. Welcome to Portland General Electric’s fourth quarter and full year 2015 earnings call. In 2015, we achieved several key objectives towards meeting our customers’ energy needs, and I’m pleased to share results with you this morning. On today’s call, I’ll provide an overview of our financial results in 2015 and initiate 2016 earnings guidance, give you an update on our operating performance, provide an update on construction at Carty, summarize the economic conditions in our operating area, and outline the status of our 2016 integrated resource plan. Following my remarks, Jim Lobdell will provide details on the fourth quarter, and annual financial results, and end with our key assumptions supporting our outlook for 2016. So let’s begin. As presented on slide four, we recorded net income of $172 million or $2.04 per diluted share in 2015, compared with net income of a $175 million or $2.18 per diluted share in 2014. This decrease in earnings per share was largely due to a record warm winter that resulted in lower residential energy sales compounded by lower than budgeted hydro, wind and the associated lower production tax credits and higher replacement power costs. Management took prudent actions and to temporary operation and maintenance reductions offset approximately $0.09 per share of the financial impacts from weather and power costs. Now looking ahead for 2016, we are initiating full-year earnings guidance of $2.20 to $2.35 per diluted share, which reflects warmer than normal weather and lower wind production in January. Jim will provide more details later in the call. Now for an operational update on slide five, employees across the company did an excellent job in 2015 of improving efficiency, reducing costs and executing our business strategy to deliver value to our customers, shareholders, employees and the communities we serve. Our customer satisfaction remains very high in all segments. Residential business and key customers placed us in the top quartile or better for satisfaction, favorability and trust according to the latest survey results. Also our 2015 generating plant availability was excellent at an average of more than 92% across all of the resources PGE operates. 2015 was the warmest year on record in Oregon. The effects of weather impacted earnings by reducing energy deliveries to the residential sector, especially during the first quarter. As a result, management normally took actions to temporarily reduce operating and maintenance costs, but also work diligently to ensure our delivery system and generating facilities operated extremely well. These actions were critical factors in helping to address the challenges pose by weather and higher power costs throughout the year. In 2015, we continue to demonstrate our leadership in delivering renewable energy and other programs to our customers. In addition to maintaining our standing as the number one renewable program in the nation, we won new awards, established a new offering for our customers and hit a new milestone. Our achievements included PGE’s two wholly-owned wind farms were recognized for being both safe and sustainable. Our newest wind farm Tucannon River is the first energy project in the nation to win the envision, sustainable, infrastructure gold award from the Institute of Sustainable Infrastructure. This award was based on PGE’s contributions related to quality of life, leadership, resource allocation, the natural world and climate risk. Our other wind farm Biglow Canyon earned a Safety and Health Achievement Recognition Award, refer to as SHARP from the Oregon Occupational Safety & Health Division. This is the first time a wind project has qualified for SHARP certification in Oregon and only the second wind project in the United States. Also we enrolled – also we open enrollment on the new renewable power option that enables customers to purchase output from a new 3-magawatt solar installation in the Willamette Valley, providing a way for more customers to support solar generation. And finally, our dispatchable standby generation program passed the 100 megawatt mark. This cost effective customer program helps meet regulatory requirements for non-spinning reserves. I’m very proud of these achievements. Now, turning to slide six for an update on our Carty Generating Station. On December 18, we declared Abeinsa, our engineering, procurement and construction contractor on Carty in default under multiple provisions of the Carty Construction agreement, and we terminated the agreement. As a part of the original construction agreement, PGE required Abeinsa to provide a performance bond to guarantee satisfactory completion of the project, in the event Abeinsa failed to fulfill their contractual obligations. The performance bond was provided by two sureties, Liberty Mutual Surety and Zurich North America for a $145.6 million. Following termination of the construction agreement, PGE in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015. Currently, we estimate the total capital expenditures for Carty will be in the range of $620 million to $655 million, including AFDC, and before considering any amounts received from the sureties under the performance bond. And we are targeting an in-service date in July of 2016. The prior Carty construction estimate of $514 million in capital costs, including AFDC was approved by the Oregon Public Utility Commission in the 2016 general rate case. We are currently in discussions with the Sureties regarding their obligations under the performance bond. And we believe they have an obligation under the performance bond to contribute funds towards completing the Carty project. In the event, the total cost incurred by PGE for Carty less any amounts received from the maturities under the performance bond exceeds the OPC approved amount of $514 million or the plant is delayed past July 31, 2016. The company would pursue one or more avenues for regulatory recovery. With regard to an update on the actual construction, all major components are on-site and are currently more than 700 construction workers on-site representing key contractors, including Dean Zimmerman, Sargent & Lundy and Black & Veatch. Now to move to slide seven, where we provide a summary of the company’s current capital expenditure forecasts from 2016 to 2020. These amounts potentially could be augmented with incremental investment related to natural gas supply, system reliability and operational efficiencies that provide value to our customers. In addition, the graph does not include any potential capital of projects from the outcome of our 2016 integrated resource planning process. We will continue to provide updates on our capital expenditure forecast in future earnings calls. Turning to slide eight, Oregon continues to exhibit several positive economic trends. First, unemployment in Oregon in December was 5.4% and approaching the range considered full-employment. Unemployment in our service area was even lower at 4.7% and compares favorably to the U.S. unemployment rate of 5%. Secondly, overall business expansion and new real estate investments continued in 2015. Investors have targeted Portland as a desirable West Coast location and evidenced by the large number of real estate transactions during the year and proposed new projects. With growth in both the number of local startups and in large Silicon Valley companies locating in offices in the region, the Portland Metro area has become one of the fastest growing areas for high-tech employment. In addition, large high-tech industrial customers continue to expand our service area and contribute to weather-adjusted load growth of more than 2% in 2015 over 2014. This is net of approximately 1.5% in energy efficiency and excludes one large paper company who ceased operations in late 2015. Finally, Oregon was once again the number one state for in migration in 2015, according to a study from United Van Lines issued in January 2016 this is the third year in a row that Oregon has received the number one rating. PG’s average customer count continues to increase at approximately 1% year-over-year and looking forward, we expect weather-adjusted load growth in 2016 of 1%, net of approximately 1.5% in energy efficiency and excluding the one large paper company. On to slide nine. With regard to the integrated resource plan, we plan to file the 2016 IRP in the second half of 2016. The IRP assumes a 20-year planning horizon with an action plan for the period 2017 through 2021. The plan will address multiple issues including replacement of our Boardman Plant, which will cease operating on coal at the end of 2020, meeting the renewable portfolio standard of 20% by 2020, additional energy efficiency and demand side actions, additional capacity that needs to meet our customers, and several other topics. Now, I’d like to turn the call over to Jim Lobdell, who will go into more depth on our financial and operating results for 2015, and provide the assumptions for our 2016 earnings guidance. Jim? James Lobdell Thank you, Jim. Turning to slide 10. For the fourth quarter of 2015, we recorded a net income of $51 million or $0.57 per diluted share, compared to net income of $43 million or $0.55 per diluted share for the fourth quarter of 2014. This increase was primarily driven by the addition of Port Westward Unit 2 and the Tucannon River Wind Farm in customer prices, AFDC related to the construction of the Carty Generating plant, and a reduction to O&M in the fourth quarter of this year, offset by an increase in share count 2015, related to the final draw in June under the Equity Forward Sale Agreement. Also, targeted earnings for the fourth quarter 2015 were reduced by warm weather, which had a negative impact of $0.05 in comparison to normal. As shown on slide 11, for the full year 2015, we recorded net income of a $172 million or $2.04 per diluted share, compared with the $175 million or $2.18 per diluted share for 2014. This decrease was largely due to the warmest year on record in Oregon, resulting in lower residential energy sales, compounded by lower than planned hydro and wind conditions, resulting in higher replacement power costs, and lower than anticipated production tax credits, and an increase in share count due to the timing of the final draw under the Equity Forward Sale Agreement. These decreases were partially offset by earnings from two additional generating clients, placed in service, Carty AFDC and a strong effort to temporarily reduce O&M spending for the year. Moving onto slide 12. For the full year, total revenues decreased $2 million. This decrease in revenues was primarily due to a reduction in residential energy deliveries, in addition to lower wholesale and other revenues. These decreases were partially offset by a 1% increase in customer prices. Purchased power and fuel expense decreased $52 million year-over-year, driven by an 8% decline in the average variable power cost per megawatt hour. The decrease was largely driven by a 3% decrease in the average price of purchase power and the economic displacement of Boardman in 2015. Net variable power costs is reported for regulatory purposes were $3 million below the baseline of the power costs adjustment mechanism. However, when adjusting for a couple of one-time transactions which did not flow to the company’s income statement. In 2015, net variable power costs were $6 million above the baseline, reflecting lower wind and hydro generation, partially offset by optimization of the overall power supply portfolio. This compares to $7 million below in 2014. Moving on to slide 13, operating and maintenance costs totaled $507 million in 2015, $23 million higher than in 2014 and $13 million below the midpoint of our original 2015 guidance range of $510 million to $530 million. The higher costs in 2015 were driven primarily by the following increases, $9 million and costs related to the addition of the Port Westward Unit 2 and Tucannon River Wind Farm and $14 million in administrative and general costs including $5 million increase in information and technology expense and an increase of $3 million in non-labor and outside services expense. The reduction in O&M spending relative to our original guidance reflects the company’s commitment to attempt to offset reduced earnings from warm weather in the first quarter of 2015. Depreciation and amortization expense was at the midpoint of our guidance range and increased $4 million of $301 million in 2014 to $305 million in 2015. The increase was primarily driven by a $26 million increase expense and the capital additions offset by a $22 million reduction of the amortization of deferred regulatory liabilities from the Trojan spent fuel settlement and tax credits as they were refunded to customers in 2015. Interest expense increased $18 million in 2015 compared to 2014. This was driven primarily by a $9 million increase resulting from lower allowance for borrowed funds used during construction, combined with a $7 million increase in interest expense due to higher debt outstanding in 2015. Other income net decreased $16 million year-over-year as a result of the $16 million decrease and the allowance for equity funds used during construction as the Tucannon River Wind Farm and Post Westward Unit 2 were put into service in December 2014. Lastly, income tax has decreased $16 million year-over-year, largely due to a $14 million increase in production tax credit and the addition of the Tucannon River Wind Farm. The company’s effective tax rate decreased to 20.7% from 26% in 2014. We did not take bonus depreciation in 2015, and we have not taken it since 2010, because we have favored using production tax credits and other state tax credits with expiration dates over using bonus depreciation. Given the extension of the bonus depreciation through 2019, we will continue to assess our approach each year. On to slide 14, we continue to maintain a solid balance sheet, including strong liquidity and investment grade credit ratings. As of December 31, 2015, we had $550 million in cash, available short-term credit and letter of credit capacity, $867 million of first mortgage bond issuance capacity and the common equity ratio of 50.5%. The company has a $500 million revolving credit facility to meet the company’s liquidity needs, which has a maturity date of November 2019. The company has additional letter of credit facilities totaling $160 million. In January of this year, PGE issued a $140 million of 2.51% Series First Mortgage Bonds, which were used to fund an early redemption of two outstanding Series First Mortgage Bonds. The company plans to potentially issue up to an additional an $160 million of long-term debt in 2016. Moving onto slide 15, on November 3, 2015, The Oregon Public Utility Commission issued an order that when combined with customer credits results in an overall increase in customer prices of approximately 0.7%. These prices were effective in two phases, a 2.5% decrease in the January 1, 2016, and a 3.3% increase when Carty comes into service, provided it happens by July 31, 2016. The changing customer prices will reflect a return on equity of 9.6%, a capital structure of 50% debt and 50% equity, a cost of capital of 7.51%, a rate base of $4.4 billion, and an annual revenue increase of $12 million. As shown on slide 16, we’re initiating full year 2016 earnings guidance of $2.20 to $2.35 per diluted share. This guidance is based on warmer than normal weather, and lower wind production in January 2016, which resulted in roughly an $0.08 impact on earnings. Additional assumptions include the following: retail delivery growth of approximately 1%, weather adjusted, and excluding one large paper company; average hydro conditions, wind generation based on five years of historic production or forecasted studies when historical data isn’t available; normal internal plant operations, operating and maintenance costs between $515 million and $535 million; depreciation and amortization expense between $315 million and $325 million; and the Carty Generating Station in service by July 2016, at approximately the OPUC authorized capital amount of $514 million. Back to you, Jim. James Piro Thanks. As we begin 2016, we are moving forward on initiatives that drive value for our customers and shareholders. Slide 17 displays our key objectives for 2016. First, maintain our high level of operational excellence with a focus on employee and public safety, meeting our operational and performance goals and meeting our financial performance targets. Second, bring Carty Generating Station into service, on or before July 31, 2016. And third work collaboratively, with all of our stakeholders, to prepare our 2016 integrated resource plan and its associated action plan, to meet our customer’s future energy needs, using resources that provide the best long-term balance of cost and risk. And now operator, we are ready for questions. Question-and-Answer Session Operator Thank you. [Operator Instructions] And our first question comes from Michael Weinstein of UBS. Your line is now open. Michael Weinstein Hi, good morning. James Piro Good morning, Michael. James Lobdell Good morning. Michael Weinstein Hey on the results for 2015, we say that you have a temporary reduction O&M of about $0.09 I believe you said at the beginning of the call. James Piro Yes. Michael Weinstein Okay. So, why is that temporary and I’m guessing that since, it’s temporary does that $0.09 is now responsible for higher O&M in 2016 guidance. So, going forward in 2017, we would subtract that $0.09 out again to normalize? James Lobdell No, Mike, I wouldn’t do that. What we did in 2015 was to the extent that we could push off any particular activities and non-impact safety and reliability or customer satisfaction, we took account for that, but I wouldn’t add that back into the following year, just here point in time. We still need to assess or what needs to happen there. James Piro Yeah. In 2016, our O&M is in line with what was allowed in the general rate case and that’s for work that needs to be done on our system, to meet our reliability and customer service obligation. What we looked at in 2015, we’re delaying some types of work and it’s not something we can do permanently. Michael Weinstein Right. And also on the Carty project, is there any chance that you guys can finish the project before July right now or is it something you’re willing to talk about in terms of is the project ahead of schedule or is it exactly on schedule and any slippage by the overall? James Piro Well, we have a schedule and it has this completing the project in July and we have some room, but everything is going to have to go perfect. We have to go through the startup, we have to get all the construction work completed. As I mentioned earlier, we mobilized enough people on the site to do the work. Now, we have to see the productivity and we have to see everything go as we have planned. And so, we’re going to watch it pretty carefully. We’ll know a lot more at our next earnings call. But I would say everything is fully going at this point, and we’re moving and things are happening at the site. Michael Weinstein At what point do you think you’ll finish negotiating with surety providers to figure out exactly how much they are going to assume? James Piro That’s going to be a process. We do have a meeting scheduled in March, but that will be just the first step in the process with them. Michael Weinstein Okay. All right. Thank you very much. Operator Thank you. And our next question comes from Paul Ridzon of KeyBanc. Your line is now open. Paul Ridzon Good morning. How are you? James Piro Good morning. James Lobdell Good morning, Paul. Paul Ridzon Can you parse out the $0.08 headwind we’re facing? How much of that is wind and versus weather? James Lobdell Most of that is all weather, and about $0.02 of it represents wind. And then there’s the PTCs in there as well, which is about a 7.5. Paul Ridzon Okay. Just back to Mike’s question, so how much of the $0.09, how much was differing versus actually just not doing, and then how much of that $0.09 is creeping into this 2016? James Lobdell The O&M forecast that we have provided, the range is to do the work, we need to do in 2016. Things that we didn’t get done in 2015 or delayed or basically incorporated in our budget for 2016. So, we have a budget now. We have a work, we have to get completed and I think, we are aligned with our budget for this year. James Piro And that’s embedded in our guidance. Paul Ridzon Okay. And then just on history of Carty, $514 million was approved and now you’re looking $620 million or more. What kind of – what’s the delta there? James Lobdell We expect cost to $140 million, we check the high-end versus the $514 million. So basically what we’ve got there is we have to remove liens that have been perfected associated with the site. We’ve got a lot of rework that needs to be done, cost to complete the construction, which is closed construction and start-up, site stabilization, their delayed costs that can include productivity, AFEDC and contingency and other costs. Paul Ridzon You are successful in securing the full surety. Carty will come into under budget? James Piro Well, I think it’ll come in pretty much at budget. I think the 514 included the contractor meeting the obligations under the agreement. So, our sense would be is, if the sureties do what we think they’re responsible for doing, we would come in at our budget amount. Paul Ridzon Okay. Thank you very much. James Piro Thanks, Paul. Operator Thank you. And our next question comes from Chris Turnure of JPMorgan. Your line is now open. James Piro Good morning, Chris. Chris Turnure Good morning, guys. James Lobdell Good morning, Chris. Chris Turnure Could you give some more color on Carty? Just another question on that front. How do you plan on financing the incremental cash that you’re going to need to fund that this year? And have you had any conversations with the commission yet, and kind of walking them through what’s going wrong throughout the process and to the degree that you kind of do about it even before late December? James Piro Well, the first part of the question is, how are we going to go about funding the incremental capital associated with the project. I think as we have mentioned previously, we got plenty of capacity under our short-term earnings, access to bank loans that we can provide in order to cover any incremental costs that we have to fund that we’re not getting from the sureties associated with the project. On the regulatory side… James Lobdell Yeah. I can cover that. We’ve been keeping the PUC informed throughout the process. We recently have been asked to provide an update on Carty through a public meeting. However, it hasn’t been scheduled yet. Probably, that meeting would happen sometime in March or April. Chris Turnure Okay. And have you disclosed, how much, let’s say a one month delay in the project past July 31 would mean for EPS? James Lobdell No. We haven’t. Chris Turnure Okay. And then, my second question is just on the legislation now kind of making its way through the legislature over there. Can you give me some color on what do you think the chances of passage are, and then what that would mean for the next, let say five years to seven years of capital deployment and renewable growth opportunities for you guys, because certainly in the long-term it would be a big benefit, but I am focused a little bit more on the near-term. James Lobdell Yeah. So let me give you an update on – it’s called the Oregon clean electricity plan, it’s called H.B. 4036 is the actual bill number. It just passed out of the House’s Energy and Environmental Committee on a 6-4 vote. It will now go to the floor for a vote at the House level. If it passes there than it would move to the Senate Committee, and then worked its way to the Senate. The bill essentially does two major things; number one, it eliminates coal in Oregon by 2030 and for us up to five years later for Colstrip up to 2035. And then, it increases our renewable portfolio standard targets, mostly in the out year. So it’s a 50% standard by 2040. The interim targets are 27% in 2025 versus the current RPS standard of 25%. 35% by 2030, 45% by 2035 and 50% by 2040. So you can see from those new numbers, the bulk of the changes would be in the outer years, as we go to a 50% RPS standard. This will all be factored into our integrated resource plan as we work through the process in this case, because we wouldn’t want to go long generation as we think about a higher RPS standard. So, it’s all been factored into our planning at this point, but it is all dependent on that while past seen the legislature and signed by the Governor. So, that’s kind of where it is. We have got support, a number of people are supporting the measure, and there is some opposition to the measure. So, we’ll just have to see how it plays out. Chris Turnure Great. That’s helpful. Thanks. Operator Thank you. And our next question comes from Brian Russo of Ladenburg Thalmann. Your line is now open. Brian Russo Hi, good morning. James Piro Good morning. Brian Russo Could you just remind us the amount of capacity you need to meet the 20% RPS in 2020, any backup capacity necessary and then, the number of megawatts you need to replace on Boardman? James Piro So, in 2020, the RPS standard goes another 5%. It’s probably a very similar to Tucannon River Wind Farm, it’s probably around 100 average megawatts. So, it’d be very similar to adding another Tucannon River Wind Farm. If you’re thinking about the size of that, that was about 267 megawatt of nameplate capacity. So, a lot of it will depend on capacity factor. So, that’s kind of what we’re looking at it. The timing of that still kind of up in the air. With the extension of the PTCs, we’ll have to evaluate when is the right timing for that unit, because we do have renewable energy credits that we can apply. And so, we’re looking at what’s the right timing of that, especially given the extension of the production tax credit. That will all be a topic of our integrated resource planning discussion. As it relates to Boardman, our piece of the capacity is about 520 megawatts, hydropower owns 10% of the project. And so, that is again being evaluated on what to – how we replace Boardman in the IRP. Obviously, I think, prior to H.B. 4036, I think our thinking was likely a natural gas prior plant would be that the type of thing we would do, and we would do and we will have to do an RFP like we did before, but as you know, we’ve said before, Carty has been designed as the two-unit site. So, it would be a very good site to look at the second unit there. But with a 50% RPS standard, we have to kind of consider the entire mix in the long-term trajectory and what’s the right kinds of resources we’re going to need. So, it’s not clear to me at this point, what we will do to replace Boardman, whether it will be more capacity in renewables or base load gas generation. So, that really is the topic of the IRP and we’re just now in the process of developing portfolios that we can look at to see what provides the best balance of cost and risk going forward. Brian Russo And would you need backup power for the – an additional wind farm? James Piro Yeah. As we look at the renewables, as you know, they are not firm energy, at least we haven’t found at this point that really correlate directly with our loads. So, it would be a wind farm, backed up by some type of capacity resource, either a simple cycle turbines or reciprocating engines like Port Westward Unit 2. Again, we have capacity needs. That’s something that’s been identified in the integrated resource plant as we look at what our loss of load probability study show us. And so, that is going to have to be addressed also. But our sense is, we’re going to need additional capacity as we go to a higher RPS standard. Brian Russo Okay. So, just back of the envelope $1,100 a KW for CCGT and maybe $1,500 a KW for wind, I know you talked in probably a $1 billion of potential spend, is that reasonable? James Piro Potentially, again, as you know, we have to go through an RFP. We have to ensure that we have the least cost, lowest risk projects to bring forward. As we’ve said before, we would always want to include our own self build options and I think we’ve demonstrated from the construction of Port Westward Unit 2 and Tucannon, that we can deliver those projects on time and on budget. So, we will want to provide our own projects. We have some sites that are very competitive sites, at least on the gas side, and we’ll continue to look for those wind farms, and wind projects that can meet our renewable standard. Brian Russo And when would you expect to get acknowledgement from the OPUC, and when would be RFP process start, and then finish? James Piro Probably in 2017, we expect the acknowledgement from the commission. James Lobdell We’ll file in the later part of this year. We would expect a position decision in early part of 2017. Then, we will go into an RFP process, where hopefully we’d know the decision by late 2018 and then, move forward from there. Brian Russo Okay. Great. And then, what are the regulatory options for recovery of the Carty costs above what’s in the general rate case? James Piro Well, there’s couple of things. First of all, it depends on what the number is. Obviously, if we’re above that, but only slightly, we’ll evaluate that, and we’ll have to understand the reasons for that. But, the way we would do that is through general rate case, and next subsequent rate case. At this point, we’re not planning on filing a 2017 general rate case, looking to 2018 as a potential. We will then file that case with what we think our prudent capital costs, and we will go through the process to support those costs. If the project is delayed beyond July 31, we will enter into discussions with the stakeholder groups to talk about options to recover the costs. A lot of it will be dependent on when that project will be going online, and we’ll determine what’s the best way to move that forward. We have options and – but a lot of it depends on when that project would come online. Brian Russo Okay. And then, I assume that midpoint of your guidance assumes a zero balance on the PCAM? James Lobdell Yes. Brian Russo And when was the net variable cost set in terms of gas prices or prevailing commodity prices? James Lobdell It was set in November, when we file our final update, which includes cost curves and all our contracts that we have in place. Usually, we’re about 95% hedged against our forward position. So, we’ve locked in those financial or physical contracts on gas as well as any electric purchase contracts. So we’re pretty balanced in November. So, than the variabilities we deal with are hydro, wind and plant availability. So those are things that we feel. The good news is that hydro is about normal this year. We’ve had a really good snowpack early on and we’ll have to see how it goes for the rest of the year, because that normal forecast does assumes normal precipitation for the rest of the cycle. So, we’ll watch that pretty carefully as we see a snowpack build hopefully. Brian Russo And what appears to be lower gas prices now versus I guess what was implied in November, are you able to optimize your generation fleet to kind of capture that spread, so to speak? James Lobdell Not necessarily. A lot of it will depend on what happens in markets in terms of opportunity, but our plans are committed to meet our retail load. And so, we’ve already locked in essentially the gas price for those plants to run and meet our retail load. There may be some opportunity, but probably the only real value is that, if for example, we have lower wind, a lower gas prices would lower our replacement cost instantly with hydro. But on the flipside, if we have a lot of hydro, low gas prices depressed the market price, so we don’t get as much value. So it has kind of pluses and minuses as we think about it. But right now, we’re hedged against where our loads and resources are. Brian Russo Okay. Thank you. Operator Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open. James Piro Hi, Michael. James Lobdell Hi, Michael. Michael Lapides Hey, guys. Congrats on a good year and a good start to 2016. Just curious, thinking about the RFP process and thinking about the IRP as well, does the State of Oregon need capacity or energy or does simply your service territory does and so one of the alternatives in all of this process could be simply increasing the amount of power that could be sent into the Greater Portland area from other parts of the state. The reason that’s, I’m kind of thinking through that is, there are – we’ve seen in other states over the years, Louisiana, Mississippi great example of this also in the desert Southwest, where merchant projects that were in a state like in Oregon or like Louisiana or Arizona, roundup getting bid into RFPs and sold at a price that was well below new build cost. Now, some of the ones in your state, they’re not really in downtown Portland, so there it have to be a transmission alternative, but I think that largely will depend on, is it a state need or is it a part of the state need for new capacity in energy? James Piro So, let me talk about that generally. In the last IRP, projects that were available or bid in, and they were not competitive with new generation, just because of higher heat rates and older units. So they were not successful. And to that extent, nothing has been built since then to my knowledge in the region in terms of new gas fire generation. James Lobdell And then, on top of that, you got several plants that will be taken out of the regional mix, but essentially are the – plants will be going away, Boardman will be going away in 2020, and what has been added to the market place has been mostly in variable energy resources… James Piro Under a contract. James Lobdell Yeah. James Piro Typically under contract. So, you think about Oregon, and maybe the region, I see has been more capacity deficit, our study show that. And there is just not capacity sitting on the sideline. On an energy basis, it’s a really kind of tough issue as we see all these renewables show up in the system. Obviously, what’s going on in California with the Duck Curve and all the solar energy down there, those are the things we’re looking at, but the strong to California is only so large. And so, we have to think about the reliability of that supply as well as the costs. So, those are things that we are evaluating in the IRP, but I would clearly say, there is a need for additional capacity in the region, especially as we add in more variable resources. Michael Lapides Got it, guys. Thanks. One follow-up, unrelated to that. You made some minor changes to your base CapEx forecast in today’s disclosure. Can you just kind of walk us through what drove those changes? James Lobdell Yeah. Effectively, it was just a shifting of dollars associated with our customer information, and meter data management project, and that was essentially it. Michael Lapides Meaning, moving stuff into 2016 from it, can you just like – which years went up, which years went down and what was the – and was that the main driver of that, when I think about 2016, 2017, 2018 or so? James Lobdell Well, the movement of dollars from 2017 to 2016. Michael Lapides Got it. Okay. So, you just moved up the project a little bit. James Lobdell Yes. Michael Lapides Got it. Thanks, guys. Much appreciate it. James Lobdell Thanks Mike. Operator Thank you. [Operator Instructions] And our next question comes from Paul Patterson of Glenrock. Your line is now open. Paul Patterson Good morning. James Piro Hi Paul. Paul Patterson Just on H.B. 4036, looks quite ambitious, and I haven’t checked. When it passed, I guess it was about yesterday. Were there amendments that addressed some of the issues that I guess are being brought up by the Oregon PUC? I guess, was there any big changes, or would those issues addressed or do you think that – I mean, it looks like it passed with a pretty good margin, I mean I’m just sort of wondering? James Piro Yeah. It passed to explore, I don’t recall if there is – I was talking to Dave yesterday, there weren’t any major amendments, and there might have been a few tweaks, but nothing that was material to way legislation would setup. I think the important thing to note is that it does still have the cost cap, and that’s currently in the legislation today. It also added another standard around reliability. So it has provided certain protections for our consumers that we think are adequate to address the concerns the commission has raised. Our evaluation looking at price impacts on consumers over the lifecycle is Bill, is somewhere in the 1.5% higher prices. So it’s not materially higher. As I said, the bill has passed, the House Committee, it’s going to the House floor for vote. It can then move to the Senate, where we could see potential other amendments, and we’ll have to see how that plays out in the coming weeks. Paul Patterson It looks like it’s on schedule for the House passage next week – early next week? James Piro That’s correct. And then, it goes to the Senate, Senate Business and Transportation Committee. Paul Patterson Okay. And is energy efficiency part of the RPS standard or is that separate? In other words, I mean, does energy, because I did notice this regional for state thing that was big pushing energy efficiency, is that part of getting to be the standard? James Piro No, because that just reduces our load energy efficiency. It just measures that. We don’t want to continue our commitment to energy efficiency. We use the Energy Trust of Oregon to determine what is the least cost, lowest risk energy efficiency and how to acquire that. We do a very detailed study in our IRP to determine what that is. And so, I don’t think that changes dramatically in this legislation. It just continues to support the need for energy efficiency, but it does not count against the RPS standard in a sense that it’s part of the – how we meet retail load. It would reduce retail load, but it doesn’t necessarily count as – against the percentages. Paul Patterson Okay. Excellent. And then, just in terms of obviously this CapEx forecast, we should expect that once this – we get more information on H.B. 4036 and your IRP, that – those numbers will probably be considerably higher, I would expect, correct? James Lobdell Yeah. I think the question we have to ask and we’ll be looking at this in the IRP is, given the shutdown of Boardman in this high RPS standard, what’s the right timing and quantity of renewables we need to add to the grid, kind of to get us to the 50%. Because you wouldn’t want to necessarily agitate base load gas generation, and then, find out that you have too much generation as you go to a 50% RPS. So we’re going to have to think very, very smartly about the right mix of resources and the trajectory to get to that 50% RPS, and the bill does allow us to may be pre-build ahead of the need if we can demonstrate that’s the cost effective thing to do. So that’s really the magic here in trying to figure this all out is, what’s the right timing of doing this in a way that provides the least cost, lowest risk for our customers. Paul Patterson Okay. Great. The rest of my questions have been answered. Thanks so much. James Lobdell Thank you. James Piro Thank you. Operator Thank you. And our next question comes from Michael Weinstein of UBS. You line is now open. Michael Weinstein Hey guys. A quick follow-up question. On the legislation, as a co-owner of Colstrip 3 and Colstrip 4, just wondering what do you see, how do you anticipate the disposition of that plan once coal by wires eliminate 2035 for it, under the legislation, what do you see happening with it? James Piro So, we’ve thought a lot about that. Obviously, our plan under this would be to recover all the capital costs and decommissioning costs through 2030 or 2035 depending on – the legislation allows us to keep the plan in customer prices through 2035. So, beyond that, the question is, what would we do with the plant. There is options we would consider obviously, if the plant continues to operate, it has value, we could either sell it in an auction, we could sell the power in the market. Those are two considerations as we look forward. And those are the things we’ll have to evaluate as we get closer to that period. And so, we don’t have any answer yet, but we have options. Michael Weinstein On minority owner. James Piro Yeah. We’re a 20% owner in Colstrip 3 and Colstrip 4. So, it’s not like we can decide to shut the project down. And so, we will look at that as we get closer to that timeframe, but those are the two options we would consider. Michael Weinstein Okay. I’m just wondering if there’s been any moves to try to push to sell to [indiscernible] just like they’re doing with Colstrip 1 and Colstrip 2? James Piro Well, yeah, I understand that. And… James Lobdell Yeah. James Piro In Washington, they have a prohibition from utilities buying coal output also. So, I know they’re working on their own issues around units 1, 2, 3, and 4. And we’ll have a lot to see when we get there. I think the landscape can change. Montana is a potential market. Obviously, there are other places that power could be sourced to. Yeah. Michael Weinstein Right. Okay. Thank you. Operator Thank you. And our next question comes from [indiscernible]. Your line is now open. Unidentified Analyst Hi, good morning. James Piro Good morning. James Lobdell Good morning. Unidentified Analyst Just a question on slide 14 regarding the financing. You guys have year marked about a $160 million of additional bonds you may issue. Is that currently embedded in the future testier that you have this year, and then in guidance? What’s the situation with the interest related to that? And what was the site, if you issue it or not? James Piro Yeah. Now, it is included in the guidance already. Unidentified Analyst It’s included in the rate case too. James Piro Including the rate case too. Unidentified Analyst Because I think, do we update the numbers for those bonds or? James Piro Updated for the bonds of … James Lobdell January. James Piro January, yeah. Unidentified Analyst Okay. James Piro Great thing. If you aligned up with the guidance that we have. Unidentified Analyst Okay. And then, just one follow-up question. Now, this is kind of an asset, I just want to make sure I understand it correctly. On the surety bonds, by when do you need to have some kind of resolution on those before you decide to take action at the commission? I mean, you can have the plant in service by your required service date, but when do you need to know about the recovery of the surety bonds before you go to the commission? James Piro Well, right now, our prices are based about on the $540 million, and that’s kind of the agreement we have, the next time we would address this in a subsequent general rate case. And so, we would obviously need to have that resolved by then, but if we’re looking at a 2018 general rate case, we’ve got sufficient time to address that. Again, our hope is that we will get full compensation for the cost exceedance, but that’s obviously something we have to work through with the sureties. Unidentified Analyst Okay. I appreciate it. Thank you and congratulations. James Piro Okay. Operator Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open. Michael Lapides Hey guys. Just a quick question on rate case timing again, meaning going forward. It doesn’t sound like you are going to do a lot of construction on stuff related to the RFO or RFP until the 2019 timeframe. Do you anticipate filing again between now and then? James Lobdell Yeah. Right now, our thinking is, 2018 general rate case, but a lot of that will depend on load growth, inflation, cost controls, just a number of factors that we look at. We clearly have not filed for a 2017 rate case and don’t anticipate doing that, absence something going on with Carty. So, we would likely look at 2018. We will make that decision till probably November of this year, when we finish our budget to be filed in February of 2017 for a 2018 general rate case, if we decided to do that. A lot of it will also depend on interest rates, what return on equities are doing. So, there are a whole bunch of factors will go into that decision. But right now, that’s kind of what we’re pointing towards, but we haven’t made a final decision. Michael Lapides Got it. So, you would file in 2017 for 2018, but that really wouldn’t incorporate many of the stuff coming out of the RFP process? James Lobdell Not at this point now. And to the extent there are renewable resources, we do have the tracking mechanism under the current RPS standard, that those can get track in directly when they go into service. So, we’d only be either capacity resources or something other type of thermal resources that would have to get, whether we require a general rate case. So, we could actually track in the renewables with the current standards we have and the mechanism we have. Michael Lapides Got it, guys. Thank you. Much appreciate it. James Lobdell Thank you. Operator Thank you. James Piro Okay. I think that’s the end of the calls. We appreciate your interest in Portland General Electric and invite you to join us when we report our first quarter 2016 results in late April. Thanks, again, and have a great day. Operator Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program, and you may all disconnect. Have a great day, everyone. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com . Thank you!