News Article | March 2, 2017
Houston, Texas, USA, March 02, 2017 (GLOBE NEWSWIRE) -- Texas LNG Brownsville LLC (“Texas LNG”) is pleased to announce that it has selected Samsung Engineering Co., Ltd. (“Samsung Engineering”) and KBR Inc. (“KBR”) to provide Texas LNG with pre-Final Investment Decision (“pre-FID”) Detailed Engineering and post-Final Investment Decision (“post-FID”) Engineering, Procurement & Construction (“EPC”) services for its proposed 4 million tonnes per annum (“MTA”) LNG export facility. Samsung Engineering, a minority equity owner and technical partner of Texas LNG, has already completed the Conceptual Study, Pre-Front End Engineering Design (“Pre-FEED”) and FEED for the Texas LNG Project, culminating in over 200,000 engineering-man hours. The Texas LNG Project design concept envisions constructing modular designed and pre-fabricated liquefaction trains using proven technology and standardized components in a controlled shipyard environment to reduce overall project costs, reduce complex onshore civil construction works, minimize local onsite environmental impacts, and minimize commissioning costs during permanent installation. Braemar Engineering, acting as Texas LNG’s owners’ engineer, together with Samsung Engineering and KBR, continues to identify value engineering enhancements to reduce project costs and optimize performance. Braemar Engineering is also responding to data requests during the Federal Energy Regulatory Commission permitting process. KBR, a pioneer and leader in LNG with over 40 years of continuous LNG experience dating back to the 1970s, has developed about one third of the world's LNG capacity and has extensive experience designing and fabricating more than 1.3 million tonnes of modules, including the world's first fully modularized LNG facility. KBR also has 30 years of experience with the proven and robust APCI AP-C3MR™ technology used in most world LNG operating liquefaction facilities, and which Texas LNG has chosen for its liquefaction plant design. Samsung Engineering and KBR will focus on value engineering and optimization for the proposed 4 MTA export facility to be built in two 2 MTA phases. Texas LNG aims to be among the lowest cost US LNG projects and pass savings to its LNG customers. Pre-FID Detailed Engineering, expected to begin this year, will include further design and schedule optimization, identification of long lead items and early works commitments, early preparation of purchase orders, and all due diligence in relation to technical commercial and contractual matters that will enable Samsung Engineering and KBR to execute a lump sum turnkey (“LSTK”) EPC contract for the Texas LNG plant. Agreements between Texas LNG and Samsung Engineering / KBR for pre-FID Detailed Engineering and EPC will be negotiated over the coming months. Executive Vice President and CMO of Samsung Engineering, Jae Hoon Choi, stated, “We want to firmly establish our competitiveness in LNG and have successfully completed the Texas LNG FEED in 2016. We’ve formed a multidisciplinary LNG task force consisting of LNG liquefaction process engineers, modularization specialists, and cost and schedule experts. Samsung Engineering and KBR will execute an EPC with Texas LNG and deliver a high-quality LNG plant at a world competitive price.” This significant milestone towards FID follows the recent announcement that Texas LNG has executed detailed non-binding Term Sheets with four independent LNG buyers in Southeast Asia and China for a volume of 3.1 MTA. Final Investment Decision for the development of the Texas LNG liquefaction project is expected in 2018. Texas LNG Brownsville LLC is an independent, Houston-based LNG company. The company is focused on low unit costs, realistic project size, LNG contractual flexibility, and proven liquefaction technology. Samsung Engineering is a minority equity owner in Texas LNG. Texas LNG’s initial project will be constructed at the Port of Brownsville in South Texas. The 625-acre site is strategically located on the north shore of the Port of Brownsville's deepwater ship channel which is in close proximity to natural gas supplies. Phase 1 production of 2 MTA of LNG for export to FTA and non-FTA markets is expected to commence in 2021-22. Phase 2 production of additional 2 MTA will follow depending on market demand. The Texas LNG team comprises leading technical, financial, environmental, and legal experts including Samsung Engineering, KBR, Braemar Engineering, Air Products, Honeywell, Third Point LLC, BNP Paribas, Galway Capital LP, Environmental Resources Management (ERM), K&L Gates, GreenbergTraurig, Andrews Kurth, Royston Rayzor, amongst others. Additional information about Texas LNG may be found on its website at www.txlng.com. Samsung Engineering is one of the world’s leading engineering, procurement, construction and project management (EPC & PM) companies, employing 17,000 people worldwide and delivering over 1,000 projects around the globe for over 40 years since foundation in 1970. Samsung Engineering’s business portfolio includes a full range of engineering services: oil & gas processing and petrochemical plants; power plants; environmental facilities. Samsung Engineering has substantial business in over 38 countries worldwide, with an established presence in countries such as Saudi Arabia, United Arab Emirates, Algeria, Iraq, Kuwait, Malaysia, India, Indonesia, China, Thailand, USA and Mexico. Additional information about Samsung Engineering may be found on its website at www.samsungengineering.com KBR, Inc. is a global technology, engineering, procurement and construction company serving the hydrocarbons and government services industries, employing over 22,000 people worldwide with customers in more than 80 countries and operations in 40 countries. A leader and early innovator in the LNG industry, KBR has managed and developed about one third of the world's LNG capacity. With LNG Centers of Excellence in Houston and London, supported by Perth and Singapore, KBR’s rich LNG heritage includes more than 400 studies/projects since 1970 with world-scale plants of varying capacities. Additional information about KBR may be found on its website at www.kbr.com The information and materials in this document are provided for informational purposes only and are subject to addition, deletion and modification without notice at the sole discretion of Texas LNG LLC and Texas LNG Brownsville LLC, and are not warranted or guaranteed to be correct, complete or up-to-date. The information and materials could include technical inaccuracies, other errors and are provided “As Is” without any representation or warranties of any kind. Texas LNG LLC and Texas LNG Brownsville LLC will neither accept or assume any liability, direct, indirect or consequential, of any kind arising from the use of information and materials contained in this document or linked website. This document is not to be considered or to be constituted as investment advice or as any type of offer, invitation, solicitation or recommendation in relation to the purchase or sale of any type of financial instruments or security in any jurisdiction. Any forward looking statements contained in the information and materials in this document are only predictions and are subject to risks, uncertainties and assumptions, many of which are outside the control of Texas LNG LLC or Texas LNG Brownsville LLC or its officers or representatives. These risks, uncertainties and assumptions include commodity prices, currency fluctuations, economic and financial market conditions in various countries and regions, environmental risks and legislative, fiscal or regulatory developments, political risks, project delay or advancement, approvals and cost estimates. Actual values, results or events may be materially different to those expressed or implied in this document. Given these uncertainties, readers are cautioned not to place reliance on forward looking statements. Readers are strongly advised to complete their own investigations to the accuracy and completeness of the contents of this or any other communication or document, written or oral, provided by or referred to by Texas LNG LLC or Texas LNG Brownsville LLC or its officers or representatives.
News Article | March 2, 2017
EDMONTON, ALBERTA--(Marketwired - March 2, 2017) - EPCOR Utilities Inc. (EPCOR) today filed its annual and fourth quarter results for 2016. "2016 was a defining year for EPCOR with consolidated net income at the highest in a decade reaching $309 million. This, in part, reflected a gain on the sale of EPCOR's remaining ownership interest in Capital Power Corporation," said Stuart Lee, EPCOR President & CEO. "As well, EPCOR entered Texas with its investment in the 130 Pipeline, a water supply pipeline, near Austin and is set to re-enter the Ontario market with the pending acquisition of the assets of Natural Resource Gas Limited utility in southwestern Ontario. EPCOR also reached substantial completion of the City of Regina's upgraded wastewater treatment plant - on time and on budget. EPCOR will operate and finance the new infrastructure under a 30-year contract with the City." Backed by a strong and sustainable long-term growth outlook, EPCOR increased its annual dividend to its Shareholder, the City of Edmonton, by $5 million to $146 million commencing in 2017. "In addition to a strong growth outlook and excellent financial results, EPCOR recorded its best safety performance and highest employee engagement scores in company history. These results were among the most gratifying of the year," said Mr. Lee. Highlights of EPCOR's financial performance are as follows: Management's discussion and analysis (MD&A) of the annual and fourth quarter results are shown below. The MD&A and the audited annual consolidated financial statements are available on EPCOR's website (www.epcor.com) and SEDAR (www.sedar.com). EPCOR's wholly owned subsidiaries build, own and operate electrical transmission and distribution networks, water and wastewater treatment facilities and infrastructure in Canada and the United States. The Company's subsidiaries also provide electricity, natural gas and water products and services to residential and commercial customers. EPCOR, headquartered in Edmonton, is an Alberta Top 70 employer. EPCOR's website address is www.epcor.com. This management's discussion and analysis (MD&A), dated March 2, 2017, should be read in conjunction with the audited consolidated financial statements of EPCOR Utilities Inc. for the years ended December 31, 2016 and 2015, including related party transactions (note 27) and financial instruments (note 28), and the cautionary statement regarding forward-looking information at the end of this MD&A. In this MD&A, any reference to "the Company", "EPCOR", "it", "its", "we", "our" or "us", except where otherwise noted or the context otherwise indicates, means EPCOR Utilities Inc., together with its subsidiaries. In this MD&A, Capital Power refers to Capital Power Corporation and its directly and indirectly owned subsidiaries including Capital Power L.P., except where otherwise noted or the context otherwise indicates. Financial information in this MD&A is based on the audited consolidated financial statements, which were prepared in accordance with International Financial Reporting Standards (IFRS), and is presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company's Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. This MD&A was approved and authorized for issue by the Board of Directors on March 2, 2017. EPCOR is wholly owned by The City of Edmonton (the City). EPCOR, through wholly owned subsidiaries, builds, owns and operates electrical transmission and distribution networks and provides Regulated Rate Option (RRO) and default supply electricity related services. EPCOR sells electricity and natural gas to Alberta residential consumers under contracts through its Encor brand. In addition, EPCOR builds, owns and operates water and wastewater treatment facilities and infrastructure in Canada and the Southwestern United States (U.S.). The water business includes design, build, finance, operating and maintenance services for municipal and industrial customers in Western Canada. Net income was $88 million and $309 million for the three and twelve months ended December 31, 2016, respectively, compared with net income of $65 million and $260 million, for the comparative periods in 2015, respectively. The increase of $23 million in the quarter is primarily due to the recognition of the fair value gain resulting from the sale of Capital Power shares (also referred to as the "available-for-sale investment in Capital Power") and greater favorable fair value adjustments related to financial electricity purchase contracts and interest rate swaps, partially offset by lower income from core operations, as described below. The increase of $49 million for the twelve months ended December 31, 2016 was primarily due to the recognition of the fair value gain resulting from the sale of Capital Power shares, greater favorable fair value adjustments related to financial electricity purchase contracts and higher income form core operations as described below. Net income from core operations was $51 million and $255 million for the three and twelve months ended December 31, 2016, respectively, compared with $74 million and $251 million for the comparative periods in 2015, respectively. The decrease of $23 million in the quarter is primarily due to lower transmission customer rates, lower billing charge rates, higher depreciation, and lower income related to industrial services contracts, partially offset by higher approved distribution and water customer rates. The increase of $4 million for the twelve months ended December 31, 2016 was primarily due to higher approved distribution, transmission and water customer rates, gains on sale of surplus land, and water customer growth, partially offset by higher depreciation, lower billing charge rates and lower water volumes in Canada due to higher precipitation. EPCOR's vision is to be a premier essential services utility company in North America, trusted by our customers and valued by our shareholder. To achieve this vision, EPCOR must excel at its utility operations and be successful in its pursuit of new business growth opportunities. EPCOR's electricity strategy includes maintaining and developing new distribution and transmission infrastructure in its franchise service area as well as the development and / or acquisition of new rate-regulated or contracted assets and operations outside of its service area. EPCOR's water strategy includes maintaining and developing new water and wastewater infrastructure within its municipal franchise service areas and the development and / or acquisition of new rate-regulated or contracted assets and operations outside of its service areas. This includes design, build, finance and operate services for municipal water and wastewater treatment infrastructure and the provision of water and wastewater treatment services and potable and process water for industrial customers. We believe the long-term outlook for the North American electricity and water and wastewater treatment businesses remains strong. The demand for electricity and water and wastewater infrastructure in North America is expected to increase due to population growth, aging infrastructure, water scarcity and increased consumer expectations for reliable power, safe, high quality water and environmentally responsible wastewater treatment. Over the next five years we plan to invest in electricity and water and wastewater treatment assets where appropriate returns are expected, operational excellence can be delivered and the environmental impact is acceptable. We will seek growth opportunities within our existing utility footprint, in addition to the new geographies in which we have made recent acquisitions. This includes exploring opportunities in natural gas distribution through acquisitions and greenfield development. EPCOR also intends to invest in the area of renewable energy generation, including solar and bio gas facilities to enhance our environmental performance. Maintaining our investment grade credit rating to ensure access to capital through existing and new credit facilities and public or private debt financing offerings remains a priority. We recognize that we are not immune to recessionary trends and will remain vigilant to maintain a prudent balance of rate-regulated and contracted operations within our financial capacity. Operational and financial performance is measured through financial and non-financial measures that are approved by the Board of Directors. The measures fall under four broad categories composed of: health, safety and environment; people; growth (financial); and operational excellence, and are applied across the Company. There are specific measures established for each business unit and the corporate shared service group in alignment with the Company's strategy. For example, under the health, safety and environment category, safety performance is based on total recordable injury frequency. Business unit measures under the operational excellence category are focused on customer related measures relevant to the particular business unit, such as customer satisfaction survey results and service reliability. Recordable injury frequency rates for EPCOR overall were better (lower) in 2016 as compared to 2015. We remain committed to building a culture that supports a workplace free of occupational injury and illness with minimized harm to the environment. Segment performance measures are discussed under Segment Results of this MD&A. The Company sold 5,901,850 and 9,141,636 common shares of Capital Power, respectively, for net proceeds of $135 million and $204 million for the three and twelve months ended December 31, 2016, respectively. As a result of the sale of Capital Power shares, for the three months and twelve months ended December 31, 2016, the Company reclassified fair value gains of $30 million and $42 million, respectively, from other comprehensive income to net income. These sales were consistent with the Company's intention to sell the shares over time as market conditions permit. At December 31, 2016, the Company owned 249,364 common shares of Capital Power which were subsequently sold for net proceeds of $6 million in January 2017. Acquisition of the Assets of Blue Water Project 130 L.P. and Cross County Water Supply Corporation On August 19, 2016, the Company completed the acquisition of the assets of Blue Water Project 130 L.P. (Blue Water) and Cross County Water Supply Corporation (CCWSC) through EPCOR 130 Project Inc., a wholly owned U.S. subsidiary, and 130 Regional Water Supply Corporation, a Texas Water Supply Corporation of which EPCOR 130 Project Inc. is the sole member. The total consideration was $82 million (US$64 million). The Blue Water and CCWSC assets include an 85 kilometer water supply pipeline, near Austin, Texas, U.S., with designed capacity of nearly 68 million liters per day, along with groundwater well production systems and long term wholesale water supply agreements (collectively the EPCOR 130 Pipeline). $48 million (US$37 million) of the total consideration was paid at closing with the balance to be paid in the future, the majority of which is contingent on securing new long term contracts for the supply of water. The Company has recorded the full amount of this contingent consideration at fair value based on expected growth in the region. The Company funded the closing payment by issuing US$40 million of private debt notes with a 25-year term. The allocation of the purchase price was determined based on the relative fair values of the acquired assets and liabilities. For further information on the fair value estimates, refer to the audited consolidated financial statements of EPCOR Utilities Inc. for the years ended December 31, 2016 and 2015. During 2016, Water Services reached substantial completion of the wastewater treatment facility for the City of Regina under a public-private partnership. The construction was completed on time and on budget and the Company continued to operate the existing wastewater treatment facility during the construction period. The upgraded facility meets higher effluent standards as established by the Saskatchewan Water Security Agency, in response to the Federal Wastewater Systems Effluent Regulations, in addition to meeting the needs of a growing population. Water Services will continue to operate the wastewater treatment facility for the City of Regina for a total term of 30 years. In February 2015, Suncor gave the Company notice that it would exercise its contractual rights to buy back the leased assets and terminate the related financing and operating agreements including the transfer of assets and operations back to Suncor over an 18-month period. The transfer of assets and operations back to Suncor was completed in August 2016 in accordance with the terms of the notice. This event did not have a material impact on the Company or its operations. Consolidated revenues were lower by $49 million and $64 million for the three and twelve months ended December 31, 2016, respectively, compared with the corresponding periods in 2015 primarily due to the net impact of the following: We use income from core operations to distinguish operating results from the Company's water and electricity businesses from results with respect to its investment in Capital Power and changes in the fair value of financial instruments. In the first quarter of 2016, the definition of income from core operations was revised to exclude changes in the fair value of financial instruments. The change in the fair value of financial instruments is the difference between the opening fair value of the derivative instruments for the period and the closing fair value of the derivative instrument. Income from core operations is a non-IFRS financial measure which does not have any standardized meaning prescribed by IFRS and is unlikely to be comparable to similar measures published by other entities. However, it is presented below as it provides a useful income performance measure of the Company's core operations and may be referred to by debt holders and other interested parties in evaluating the Company's financial performance and in assessing its creditworthiness. Changes in each business segment's operating results compared with the corresponding periods in 2015 are described in Segment Results below. Explanations of the remaining variances in net income for the three and twelve months ended December 31, 2016 are as follows: EPCOR's Water business segment's primary objective is to provide safe and reliable water and wastewater services while meeting or exceeding all environmental requirements and delivering value to customers and the shareholder. Water Services operates in Canada and the U.S. The majority of Water Services' income in Canada is earned through a performance based rate tariff charged to its Edmonton customers. The performance based rate (PBR) tariff is intended to allow Water Services the opportunity to recover its costs and earn a fair rate of return while providing an incentive to manage costs below inflation and other prescribed adjustments built into the tariff. In October 2016, EPCOR's Water Services segment received the decision related to its 2017 - 2021 Edmonton water and wastewater PBR application. The decision reduced the return on equity (ROE) from 10.875% to 10.175%. The decision is not expected to have a material impact on the Company's results. Water Services also operates in the U.S. states of Arizona, New Mexico and Texas. Customer rates in Arizona and New Mexico are subject to approval by the Arizona Corporation Commission and the New Mexico Public Regulation Commission respectively. Customer rates are intended to allow EPCOR the opportunity to recover costs and earn a reasonable rate of return under a historical cost-of-service framework. At December 31, 2016, Water Services owned three and operated 14 other water treatment and / or distribution facilities in Alberta and British Columbia. Additionally, Water Services owned one wastewater treatment facility and operated 18 other wastewater treatment and / or collection facilities in Alberta, British Columbia and Saskatchewan. In Arizona and New Mexico, EPCOR owned operations in 14 water utility districts, each containing one or more water treatment and / or distribution facilities, and six wastewater utility districts, each containing one or more wastewater treatment and / or collection facilities. The EPCOR 130 Pipeline delivers water through a 30 inch pipeline to four municipal customers near Austin, Texas under long-term contracts. While these wholesale water contracts are technically subject to Texas Public Utilities Commission appellate review, they are considered to be effectively unregulated. Water Services' core market is stable as Water Services is the supplier of water and provider of wastewater services within its various operating districts. Operationally, the facilities owned or managed by Water Services generally performed according to plan in 2016. In the third quarter of 2016, persistent rainfall throughout the North Saskatchewan River watershed significantly impacted the river's water quality. Edmonton and region residents were asked to reduce water consumption for a short period of time. EPCOR was able to maintain the required quality of Edmonton's drinking water throughout the period. In addition, Water Services provides competitive contract-based water and wastewater services, including financing, in certain arrangements, to municipal and industrial customers. In August 2016, several agreements with Suncor were terminated and all financing arrangements and leases were settled and repaid to the Company. Work on several significant projects within Edmonton progressed in 2016. These projects include the annual water main renewal program to improve Edmonton's water distribution system, water distribution line relocation as a result of the City's light rail transit expansion, construction of a hydrovac sanitary grit treatment facility at Gold Bar and upgrades to pre-treatment and other infrastructure at the Gold Bar wastewater treatment facility. Water Services' operating income decreased by $4 million for the three months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to lower income related to industrial services contracts, higher chemical and power costs, and higher depreciation, partially offset by higher approved customer rates and growth. Water Services' operating income increased by $13 million for the twelve months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to higher approved customer rates and growth, gains on sale of surplus land, higher income related to industrial services contracts and foreign exchange translation gains, partially offset by higher chemical and power costs, lower municipal service margin, lower water volumes in Canada due to higher precipitation and higher depreciation. Edmonton water sales decreased in 2016 compared with 2015 mainly due to higher precipitation, partially offset by customer growth. Arizona and New Mexico water sales increased in 2016 compared with 2015 primarily due to higher average temperatures and lower precipitation during the summer months. In addition, water sales were higher due to the acquisition of the EPCOR 130 Pipeline which delivers wholesale water to customers in Texas. Distribution and Transmission's priority is to be a trusted provider of safe and reliable electricity, known for operational excellence through innovative and practical solutions. Distribution and Transmission earns income principally by transmitting high-voltage electricity through its facilities that form part of the Alberta Interconnected Electrical System to points of distribution, and from there, distributing lower voltage electricity to end-use customers. The transmission services are provided to the Alberta Electric System Operator (AESO). The distribution services are provided to electricity retailers such as Energy Services and other competitive retailers. Distribution and Transmission's assets are located in and around Edmonton and are rate-regulated by the Alberta Utilities Commission (AUC). Transmission charges a rate-regulated tariff intended to allow recovery of prudent costs and earn a fair rate of return on invested capital. Distribution earns income through a performance based rate tariff charged to its customers. The PBR tariff is intended to allow Distribution the opportunity to recover its costs and earn a fair return on capital while providing an incentive to manage costs below inflation and other prescribed adjustments built into the tariff. This segment also provides competitive contract-based commercial services related to installation, maintenance and repair of street lighting, traffic signals and light rail transit, primarily to the City. The AUC issued its 2016 Generic Cost of Capital decision in October 2016. The AUC directed that the ROE for 2016 remain at 8.3% and increase to 8.5% in 2017 for all Alberta natural gas and electricity distribution and transmission utilities. The AUC also set a deemed equity ratio of 37% for both distribution and transmission utilities targeting the utilities' maintenance of a credit rating in the A category. This decision results in a 3% decrease and a 1% increase in the deemed equity ratios for the EPCOR distribution and transmission utilities, respectively. The various true-ups related to the decision will occur over the next several years. The decision will not have a material impact on the financial results of the Company. Distribution and Transmission's operating income decreased by $13 million for the three months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to lower transmission customer rates resulting from an interim to final rate true-up in 2015 and higher depreciation in 2016. This was partially offset by higher distribution approved customer rates and higher net system access collections. Distribution and Transmission's operating income increased by $11 million for the twelve months ended December 31, 2016, compared with the corresponding period in 2015, primarily due to higher distribution approved customer rates, higher net system access collections and higher transmission customer rates. This was partially offset by higher depreciation. Distribution and Transmission's primary measure of distribution system reliability is the System Average Interruption Duration Index (SAIDI), which it focuses on minimizing. This measure captures the annual average number of hours of interruption experienced by Distribution and Transmission's customers, including scheduled and unscheduled interruptions to its primary distribution circuits. In 2016, the SAIDI was 0.92 hours which is comparable to 0.91 in 2015. Distribution and Transmission will continue with its reliability improvement programs to further address controllable factors and help maintain and improve overall system reliability. Electricity distribution volumes in 2016 were relatively flat year over year. The Energy Services' business focuses on providing cost effective retail electricity service and efficient customer care through a highly skilled, knowledgeable, caring and engaged customer service team. Energy Services earns income from selling electricity to customers under a regulated rate tariff (RRT) and default rate (customers with higher electricity volumes that are not under a competitive contract) in the EPCOR Distribution and Transmission Inc. and FortisAlberta Inc. service areas and several Rural Electrification Association service territories. The RRT is intended to allow Energy Services to recover its prudent costs and earn a return margin. Customers under the RRT are residential, farm and small commercial customers who are not under a competitive contract and receive their electricity under the RRO. Energy Services also provides billing, collection, and contact center services to other EPCOR operations and the City Waste and Drainage Services departments. Energy Services focuses on providing excellent service experiences for its customers and measures call answer performance, billing performance, and customer satisfaction. These results are reported to the AUC on a quarterly basis. Energy Services' allowed electricity revenue is determined in accordance with an energy price setting plan (EPSP) approved by the AUC. Under the EPSP, Energy Services manages its exposure to customer load and fluctuating wholesale electricity spot prices by entering into financial electricity purchase contracts up to 120 days in advance of the month of consumption under a well-defined risk management process. Energy Services received approval of their 2016 - 2018 EPSP in the first quarter of 2016 and the Company implemented the new plan in the third quarter of 2016. The plan will adapt more quickly to changes in wholesale market conditions thereby reducing EPCOR's risk with commensurately lower risk compensation. Energy Services filed the next iteration of the EPSP applicable for 2018 - 2021 in January 2017. In May 2014, Energy Services entered the competitive retail market by offering electricity and natural gas contracts to Alberta consumers under the Encor brand in order to mitigate the impact of RRO customer attrition. The expanded service offering, including green energy options, provides customers wishing to move from the RRO to a competitive contract with an EPCOR offering. Energy Services' operating income, excluding change in the fair value of contracts-for-differences, decreased by $9 million for the three months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to lower billing charge rates and lower EPSP margins. Energy Services' operating income excluding change in the fair value of contracts-for-differences decreased by $8 million for the twelve months ended December 31, 2016, compared with the corresponding period in 2015 primarily due lower billing charge rates, partially offset by higher EPSP margins and growth in competitive business. Energy Services' retail sales volumes were as follows: Energy Services' RRT sales volume decreased in 2016 compared with 2015 primarily due to a decrease in the average consumption per site. The increased default and competitive supply sales volume was primarily due to an increase in the number of competitive supply sites served, partially offset by a decrease in the number of default sites served. In 2016, we continued to invest in our infrastructure assets to improve reliability and meet increasing electricity and treated water and wastewater demands. Total capital spending and investment was higher in 2016 compared with 2015 primarily due to the acquisition of the assets of Blue Water and CCWSC, increased spending in the Distribution and Transmission segment on the installation of advance meter infrastructure for customers in Edmonton and renovations to its major work centre, and increased spending in the Water Services segment on lifecycle projects. This was partially offset by decreased spending in the Distribution and Transmission segment on growth projects and decreased spending in the Water Services segment primarily due to the completion of construction of the new laboratory and office building at the Rossdale location in 2015 as well as decreased spending at Gold Bar and at the Walker and Big Lake booster stations in Edmonton. The Company maintains its financial position through rate-regulated utility and contracted operations which generate stable cash flows. The Company expects to have sufficient liquidity to finance its plans and fund its obligations in 2017 with a combination of cash on hand, cash flow from operating activities, interest and principal payments related to long-term loans receivable from Capital Power, the issuance of commercial paper, public or private debt offerings and draws upon existing credit facilities described below under Financing. Cash flows from operating activities would be impaired by events that cause severe damage to our facilities and would require unplanned cash outlays for system restoration repairs. Under those circumstances, more reliance would be placed on our credit facilities for working capital requirements until a regulatory approved recovery mechanism or insurance proceeds were in place. EPCOR's projected capital requirements for 2017 include $500 million to $650 million for investment in existing businesses and new business development. The following table represents the Company's contractual obligations by year: Under the terms of the lease, the Company's annual lease commitments, net of annual payments to be paid to the Company by Capital Power and another company under the sub-leases receivable are as follows: All of the Company's operating lease obligations for premises, net of subleases receivable, are included in the contractual obligations table above. If Drainage is transferred to EPCOR under the current proposal, as described in more detail in the Outlook section, EPCOR will assume assets and liabilities of approximately $3.3 billion and $0.7 billion, respectively. As well, EPCOR has proposed an increase in the dividend of $20 million subject to Board and Shareholder approval. For the first year of operations, capital spending is expected to be approximately $120 million to $200 million. As a result of the acquisition of the Blue Water and CCWSC assets, the Company is committed to pay Blue Water a fee which is contingent on securing new long term contracts for the supply of water. This fee is capped at US$32 million with no time limit for payment of the fee. The Company is reasonably certain that it will be required to settle this commitment by way of cash payment and has accordingly recognized the liability for contingent consideration in the consolidated statement of financial position. During the year, the Company terminated the long term "pay fixed, receive floating" interest rate swap, related to Regina, by settlement of the outstanding liability of $14 million to the counterparty. Subsequent to the year ended December 31, 2016, the remaining short term interest rate swap was also settled. As at March 3, 2016, there were three common shares of the Company outstanding, all of which are owned by the City. In 2016, the annual dividend was set at $141 million (2015 - $141 million). As a result of EPCOR's consistent and sustainable performance, EPCOR's Board of Directors proposed to EPCOR's shareholder that the EPCOR annual dividend paid to the City be increased by $5 million to $146 million commencing in 2017. EPCOR's Shareholder approved this recommendation, and in accordance with the EPCOR Dividend Policy, this amount will remain in effect until such time as the EPCOR Board recommends that it be changed. In the normal course of business, EPCOR provides financial support and performance assurances, including guarantees, letters of credit and surety bonds, to third parties in respect of its subsidiaries. Generally, our external capital is raised at the corporate level and invested in the operating business units. Our external financing has consisted of commercial paper issuance, borrowings under committed syndicated bank credit facilities, debentures payable to the City, publicly issued medium-term notes, U.S. private debt notes and issuance of preferred shares. In the third quarter of 2016, the Company issued US$40 million private debt notes to fund the acquisition of the Blue Water and CCWSC assets. The U.S. dollar denominated private debt notes were issued with a term-to-maturity of 25 years and three months and an interest rate of 3.63% per annum. The Company has bank credit facilities, which are used principally for the purpose of backing the Company's commercial paper program and providing letters of credit, as outlined below: Letters of credit are issued to meet the credit requirements of energy market participants and conditions of certain service agreements. Letters of credit totaling $73 million (2015 - $48 million) were issued and outstanding at December 31, 2016. The committed syndicated bank credit facilities cannot be withdrawn by the lenders until expiry, provided that the Company operates within the related terms and covenants. The extension feature of EPCOR's committed syndicated bank credit facilities gives the Company the option each year to re-price and extend the terms of the facilities by one or more years subject to agreement with the lending syndicate. The Company regularly monitors market conditions and may elect to enter into negotiations to extend the maturity dates. In November 2016, the $200 million committed syndicated bank credit facility was extended by one year to November 2019. At this time, the covenants attached to both credit facilities were renegotiated. The Company has a Canadian base shelf prospectus under which it may raise up to $1 billion of debt with maturities of not less than one year. At December 31, 2016, the available amount remaining under this base shelf prospectus was $1 billion (December 31, 2015 - $1 billion). The base shelf prospectus expires in December 2017. No commercial paper was issued and outstanding at December 31, 2016 (December 31, 2015 - $98 million). If the economy were to deteriorate in the longer term, particularly in Canada and the U.S., the Company's ability to extend the maturity or revise the terms of bank credit facilities, arrange long-term financing for its capital expenditure programs and acquisitions, or refinance outstanding indebtedness when it matures could be adversely impacted. We believe that these circumstances have a low probability of occurring. We continually monitor our capital programs and operating costs to minimize the risk that the Company becomes short of cash or unable to honor its debt servicing obligations. If required, the Company would look to reduce capital expenditures and operating costs. In August 2016, DBRS confirmed its A (low) / stable senior unsecured debt and R-1 (low) / stable short-term debt ratings for EPCOR and Standard & Poor's Ratings Services confirmed its A- / stable long-term corporate credit and senior unsecured debt ratings for EPCOR. These credit ratings reflect the Company's ability to meet its financial obligations given the stable cash flows generated from the rate-regulated water and electricity businesses. The Company's continued sell-down of its interest in Capital Power in addition to the initial sale of the power generation assets in 2009 served to improve certain creditworthiness measures. The Company will continue to be indirectly exposed to power generation related risks primarily through its remaining long-term loans receivable from Capital Power until they are entirely repaid to EPCOR in 2018. Once the long-term loans receivable are repaid, the Company's creditworthiness is expected to improve even further. Improvement in the Company's creditworthiness may not result in further credit rating upgrades. A credit rating downgrade for EPCOR could result in higher interest costs on new borrowings and reduce the availability of sources and tenor of investment capital. EPCOR is currently in compliance with all of its financial covenants in relation to its syndicated bank credit facilities, Canadian public medium-term notes and U.S. private debt notes. Based on current financial covenant calculations, the Company has sufficient borrowing capacity to fund current and long-term requirements. Although the risk is low, breaching these covenants could potentially result in a revocation of EPCOR's credit facilities causing a significant loss of access to liquidity or result in the Company's publicly issued medium-term notes and private debt notes becoming immediately due and payable causing the Company to find a means of funding which could include the sale of assets. The key financial covenants and their thresholds, as defined in the respective agreements, and EPCOR's actual measures at December 31, 2016 and December 31, 2015 were as follows: In 2017, we will continue to focus on growth in rate-regulated water and electricity infrastructure. We expect this investment to come from new infrastructure to accommodate customer growth and lifecycle replacement of existing infrastructure primarily related to the Edmonton and U.S. based operations. EPCOR intends to expand our water and electricity commercial services activities and to invest in the area of renewable energy generation, including solar and bio gas facilities to enhance our environmental performance. Demand for water is expected to continue to increase and we anticipate escalating requirements for better water management practices including watershed management and conservation. We will pursue expansion of our portfolio of commercial water contracts. In January 2017, Edmonton City Council asked its administration to prepare a Letter of Intent (LOI) for the potential transfer of its Drainage Utility Services (Drainage) to EPCOR. The LOI is intended to outline the terms of a possible transfer, and is to include assurances from EPCOR on matters such as transparency into operations, public consultation, audit rights and the requirement for a public hearing should a divestiture occur in the future. It will be brought back to Council in April 2017 for further consideration. EPCOR currently operates three of the four components of the City's water utility cycle - water treatment, water distribution and wastewater treatment. The City's Drainage department operates the fourth component of the water system, the wastewater and storm water collection system. In November 2016, the Alberta government released several announcements impacting the electricity industry including the details of its Climate Change Plan. Among other things, these announcements included a cap on the RRO, a ban on door-to-door sales, and a shift to a capacity market framework from the existing energy-only market regime. These initiatives may lower the risk of RRO customer attrition in the long term. EPCOR's preliminary view is that these changes will not have a material impact. Energy Services will continue to evaluate these changes and determine any further course of action after consultations with the government and the AUC. Also in November 2016, the Company entered into a definitive asset purchase agreement to acquire substantially all of the assets of Natural Resource Gas Limited (NRGL) for consideration of $21 million, subject to certain adjustments. NRGL is a natural gas distributor in southwestern Ontario near London, providing services to approximately 8,000 residential, commercial and industrial customers in the counties of Elgin, Middlesex, Oxford and Norfolk. The arrangement requires regulatory approval from the Ontario Energy Board, for which an application has been filed. The Company expects to complete the transaction by mid-2017. EPCOR has been awarded franchises by three municipalities in the Southern Bruce region of Ontario near Kincardine to build and operate a natural gas distribution system. In March 2016, EPCOR applied to the Ontario Energy Board (OEB) for the approval of these franchise agreements. In January 2017 the OEB requested indications of interest from any parties interested in servicing these areas. A single company did indicate an interest and the OEB is now developing a process for hearing competing applications. To view an image associated with this release, please visit the following link: http://media3.marketwire.com/docs/1087660_image.jpg Our approach to Enterprise Risk Management (ERM) is to manage the key controllable risks facing the Company and consider appropriate actions to respond to uncontrollable risks. ERM includes the controls and procedures implemented to reduce controllable risks to acceptable levels and the identification of the appropriate management actions in the case of events occurring outside of management's control. Acceptable levels of risk and risk appetite for EPCOR are established by the Board of Directors, representing the shareholder, and are embodied in the decisions and corporate policies associated with risk management. EPCOR's framework for ERM is aligned with the Committee of Sponsoring Organizations 2004 Integrated ERM Framework and the ERM process follows CAN / CSA ISO 31000-10 Risk Management - Principles and Guidelines. EPCOR's ERM program and the risk management framework and process it supports is designed to identify, assess, measure, manage, mitigate and report on EPCOR's significant risks. The goal is to create and sustain business value by helping the Company reach its business objectives and strategies through better management of risk. The program promotes a common framework and language for managing risk across EPCOR. General ERM framework oversight, reviews and recommendations of risk compliance are provided by management and are based upon the objectives, targets and policies approved by the Board of Directors. The Corporate Treasurer is responsible for developing the framework and assessing risk at an enterprise level and in conjunction with the Company's internal audit function, monitoring compliance with risk management policies. The Corporate Treasurer provides the Board of Directors with an enterprise risk assessment quarterly. The business units and shared service units are responsible for carrying out the risk management and mitigation activities associated with the risks in their respective operations. These risk management activities are integral aspects of the business units' and shared service units' operations. EPCOR believes that risk management is a key component of the Company's culture and we have put into place cost-effective risk management practices. At the same time, EPCOR views risk management as an ongoing process and we continually review our risks and look for ways to enhance our risk management processes. Large scale emergencies resulting from various events discussed below may have a significant impact on the Company's ability to provide services that are considered essential services to the public. Maintaining essential services is critical to EPCOR's customers and EPCOR's reputation. The Company manages its ability to continually deliver services with emergency response protocols and business continuity plans which are periodically tested through various exercises and scenarios. These procedures provide assurance that the Company has the coordination, capacity and competence to respond appropriately to emergency situations arising from various forms of risk. The Company's Ethics Policy includes procedures which provide for confidential disclosure of any wrong-doing relating to accounting, reporting and auditing matters. The policy prohibits any retaliation against any person making a complaint. During 2016, no significant substantiated complaints with respect to accounting, financial reporting and auditing matters were received under the Ethics Policy. Our growth strategy is dependent on the development, acquisition and operation of linear infrastructure for municipal, commercial and industrial customers in Canada and the U.S. Opportunities in Canada may be impacted by depressed oil prices and the weak Canadian economy for the foreseeable future. This could slow or delay the Company's growth plans. Such growth is dependent on opportunities in the marketplace which will be impacted by the willingness of parties to sell such assets, political and public sentiment regarding third party ownership and EPCOR's cost competitiveness. These risks could result in delays or curtailment of EPCOR's growth plans. Business development projects, including acquisitions, can take a relatively long period of time to execute, exposing such projects to event and external factor risks that may emerge and thereby alter project economics or completion. For each new business development project, EPCOR seeks to ensure project success by addressing project risks, including events and external factors, as part of its due diligence process and project execution. EPCOR is subject to risks associated with changing political conditions and changes in federal, provincial, state, local or common law, regulations and permitting requirements in Canada and the U.S. It is not always possible to predict changes in laws or regulations that could impact the Company's operations, income tax status or ability to renew permits as required. In December 2016, the Government of Alberta enacted Bill 21: the Modernized Municipal Government Act which could impose restrictions on the ability of a municipally controlled corporation (MCC) to conduct its business. EPCOR, which is a MCC of the City of Edmonton, was previously exempted from the MGA and a similar exemption is not present in the new MGA. EPCOR is working to ensure the previous exemption is re-instated as the related regulations are developed. The risk could materially impact EPCOR's ability to execute on its Long Term Plan. EPCOR is subject to risks associated with the rate regulation of the majority of its operations. Such processes can result in significant lags between the time when customer rates or tariffs are applied for and the time that regulatory decisions are received. Furthermore, the regulator may deny or alter the applied for customer rates or tariffs. EPCOR's water treatment and distribution services to customers within Edmonton are rate regulated by Edmonton City Council pursuant to the 2012 - 2016 PBR Bylaw. In October 2016, EPCOR's Water Services segment received the decision related to its 2017 - 2021 Edmonton water and wastewater performance-based rate application for the five year period commencing April 1, 2017. The renewal also incorporated the costs associated with the provision of wastewater treatment services supplied from the Gold Bar wastewater treatment plant. Our ability to fully recover operating and capital costs and to earn a fair return is dependent upon achieving the performance targets prescribed in the bylaw, maintaining cost increases below inflation, managing operational risks and not exceeding approved capital additions. Rates for water sales to regional water commissions surrounding Edmonton are regulated by the AUC on a complaints-only basis. EPCOR sets the rates it charges to the regional water commissions to recover actual operating and capital costs including a fair rate of return. Water and wastewater services provided by EPCOR's U.S. subsidiaries are subject to state laws and regulation by the state regulatory commissions within Arizona, New Mexico and Texas. Our ability to fully recover operating and capital costs and earn a fair return is dependent upon achieving our capital and operating cost targets built into the rates, and meeting the customer growth and water usage targets built into the rates. Since rates are established on a historical cost basis, any new capital additions for water or wastewater infrastructure must be carefully planned and evaluated before commencement since the addition of such costs to the regulatory rate base for subsequent recovery will only take place after the new infrastructure is built and the regulator approves the rate base additions through the rate application process. The AUC utilizes a PBR structure for electricity and natural gas distribution utilities in Alberta. Under PBR, EPCOR's annual electricity distribution rates are set by a formula that is generally equal to last year's rate plus an inflation factor less a productivity factor plus a provision for additional approved capital additions. Capital projects may be applied for annually in a separate capital application (capital tracker). Our ability to recover the actual costs of providing service and to earn a fair return is dependent upon maintaining cost increases at or below inflation, achieving the productivity factor and not exceeding the approved capital additions, all as defined by the PBR formula or approved in a capital tracker application. The current performance based framework will set rates to December 31, 2017. In December 2016, the AUC issued its 2018-2022 PBR decision (Next Generation PBR) continuing the use of a performance based framework to December 31, 2022. EPCOR's electricity distribution rates for 2018 will be based on approved capital additions to the end of 2017 and actual operating and capital expenditures incurred during the 2013-2017 PBR term. The productivity factor in the Next Generation PBR term will be 0.3%, down from 1.16% currently. In addition, the Next Generation PBR decision also revised the criteria for capital tracker applications which will limit the volume of eligible capital projects. In November 2013, the AUC issued a decision in the Utility Asset Disposition Review proceeding directing that certain gains or losses due to extraordinary retirement of assets be borne by shareholders and not to be reflected in customer rates. In September 2015, the Alberta Court of Appeal (the Court) upheld the AUC's decision. The Company is responsible for ensuring that the potable water it sells to customers is safe to drink. Water Services performs continuous and rigorous quality control testing of water purification consistent with government and industry standards to prevent public health issues due to inadequately treated, stored or distributed drinking water. The ability of the water treatment plants to meet potable water quality standards is dependent on continuous water testing in order that the prescribed requirements under regulation or conventional industry standards are met. Failure to properly maintain fully functioning treatment and measurement systems could result in regulatory fines or the occurrence of public health issues. In Alberta, water quality for EPCOR's operations is regulated under the provincial Environmental Protection and Enhancement Act (EPEA). Regulation under the EPEA takes the form of an "Approval to Operate" which, among other things, specifies the quality of the treated water, the number, frequency and form of water quality testing, as well as mandatory standards for the water treatment process. The drinking water quality requirements in Alberta meet or exceed the National Guidelines for Canadian Drinking Water Quality recommended by Health Canada. Raw water quality is an important factor in the treatment of potable water. In Edmonton, we obtain surface water from the North Saskatchewan River to treat and sell to customers in the greater Edmonton area. The North Saskatchewan Watershed Alliance, among other things, aims to protect and improve North Saskatchewan River water quality by developing and sharing knowledge and facilitating workshops with members and interested parties. Drinking water quality and wastewater standards for EPCOR's U.S. operations are regulated by the U.S. Environmental Protection Agency (U.S. EPA) under the Safe Drinking Water Act and Clean Water Act, respectively. Among other things, the U.S. Environmental Protection Agency sets drinking water standards specifying the treatment, source water protection, operator training and funding for water system improvement and relies on the states and localities to carry out the standards. Oversight of water and wastewater systems is conducted by state and county authorities to the degree that they establish standards at least as stringent as the U.S. EPA. In Arizona, we obtain surface water primarily from the Central Arizona Project canal to treat and sell to customers. The Central Arizona Project conducts water quality testing upstream of the take-off points and has a formal notification process in place to notify our Arizona operations of any water quality issues that may arise. Process and compliance sampling results are stringently analyzed and trended for all groundwater and surface water systems in Arizona and New Mexico to ensure systems continue to meet all regulatory standards. Each system in Arizona and New Mexico has an Emergency Operations Plan which addresses water quality issues and provides further risk mitigation. There are no formal watershed protection groups in the Arizona and New Mexico service areas. The Arizona Department of Environmental Quality and New Mexico Environment Department oversee the water systems in their states, respectively. Water wells in Arizona, New Mexico and Texas are protected from contamination by proper well construction and system operation and management. Our operations have hazardous elements, such as high voltage electricity and hazardous chemicals that could have adverse health and safety consequences to our employees, on-site suppliers and customers. We manage health, safety and environment (HSE) risks through a management system and measure HSE performance against recognized industry and internal performance measures. We conduct external and internal compliance and conformance audits to verify that we meet or exceed all regulatory requirements. We are committed to working with industry partners to share and improve health, safety and environment practices within the industry. In 2016, all of our Edmonton water and wastewater treatment facilities, and electricity distribution and transmission operations remain OHSAS 18001 registered. We use several key information technology systems to support our core operations such as electricity and water distribution network control systems, electricity and water plant control systems and electricity settlement and utility billing systems. These systems and the associated hardware are vulnerable to malfunction and unauthorized access including cyber-attacks, which could lead to loss or unauthorized disclosure of sensitive customer or EPCOR information or extortion or otherwise disrupt operations. We take measures to reduce the risk of malicious corruption or failure of these systems, data and the hardware and network infrastructure on which they operate. EPCOR's security program is based on the ISO 27002 control framework. In applying this framework, EPCOR has implemented a series of complementary defense mechanisms, starting from the external IT perimeter down to the end user. Each layer is designed to prevent, detect and report on malicious activity. We regularly monitor our information technology protection systems and periodically employ third-party security providers to test the effectiveness and to strengthen the system as new cyber threats arise. Financial exposures associated with cyber-attacks are partly mitigated through our insurance programs. EPCOR has controls and strategies in place to mitigate the exposure to the various risks that could result in damage to EPCOR's reputation should an event occur. The company proactively maintains positive and transparent interactions with stakeholders. In addition, EPCOR communicates with stakeholders and the media when issues first arise and actively monitors social media in order to address reputational matters before they escalate. There are a variety of environmental risks associated with EPCOR's water and wastewater operations and its electricity distribution and transmission businesses. EPCOR's power and water operations are subject to laws, regulations, and operating approvals which are designed to reduce the impacts on the environment. An environmental event could materially and adversely impact EPCOR's business, prospects, reputation, financial condition, operations or cash flow. Furthermore, such incidents could result in spills or emissions in excess of those permitted by law, regulations or operating approvals. Environmental risks associated with water and wastewater operations include wastewater discharge, biogas release, and residuals management. EPCOR's wastewater operations are regulated with stringent wastewater treatment standards and controls covering quality of treated wastewater effluent as well as mandatory improvements to the wastewater treatment processes. Water and wastewater technologies and supporting processes are continuing to evolve and are influenced by more stringent regulation and environmental challenges. Failure to identify and deploy viable new technologies to meet these regulations and challenges could undermine the competitiveness of EPCOR's market position and exclude it from some market opportunities. Risks associated with electricity distribution and transmission operations include the unintended environmental release of substances such as oil from its oil-filled pipe-type cable, hydraulic oil and polychlorinated biphenyl transformer fluid. To the best of our knowledge we comply, in all material respects, with the laws, regulations and operating approvals affecting our facilities, and minimize the potential for incidents by incorporating environmental management practices in our strategy, policies, processes and procedures. To achieve this, we require each facility to have an environmental management system (EMS) which is based on the ISO 14001 standard. These systems encompass the identification of the scope, objectives, training and stewardship of our environmental responsibility. Each plant and facility is also subject to third party environmental audits to help ensure conformance with the EMS and compliance with all regulations. The Edmonton waterworks system (including the Rossdale and E.L. Smith water treatment plants) achieved EnviroVista Champion status as of June 2011. In 2016, all of our Edmonton water treatment facilities and reservoirs, the Gold Bar wastewater treatment plan, the Evan-Thomas water and wastewater treatment facility in Kananaskis, Alberta, our electricity distribution and transmission operations and our street lighting, traffic signal, light rail transit, hydrovac and cathodic protection operations remain ISO 14001 registered. The Company is also in the process of obtaining ISO 14001 registration for its Canadian water distribution and transmission operations. Compliance with future environmental legislation may require material capital and operating expenditures. Failure to comply could result in fines and penalties or the regulator could force the curtailment of operations. There can be no assurances that compliance with or changes to environmental legislation will not materially and adversely impact EPCOR's business, prospects, financial conditions, operations or cash flow. A variety of intentional, accidental or natural occurrences could cause interruption of EPCOR's operations and result in lost revenues or additional costs to resume operations including repair costs. Business interruption due to operational failure in Water Services and Distribution and Transmission is managed through inherent redundancy and sound maintenance practices. The quality of raw source water can be affected by such things as hydrocarbons and other inorganic or organic contaminants entering water ways and aquifers. Depending on the type and concentration of the contaminant, their removal may be beyond the capabilities of water treatment plant processes. This could result in the water treatment plants being shut down until the contaminants become diluted to the point where they can be treated within the water treatment plant capabilities. The ability of the water treatment plants to meet potable water quality standards is dependent on continuous water testing in order that the prescribed requirements under regulation or conventional industry standards are met. Failure to properly maintain fully functioning treatment and measurement systems could result in regulatory fines, lost revenue or the occurrence of public health issues. Our maintenance practices are augmented by an inventory of strategic spare parts, which can reduce down-time considerably in the event of power or water system interruptions. Maintenance and capital plans are determined annually based on rigorous assessment of its equipment and by continually monitoring the condition of assets. Although water and power facilities have operated in accordance with expectations, there can be no assurance that they will continue to do so. To the extent we experience insufficient raw water supply or extreme raw water conditions, delivery of water and associated revenues may be negatively affected. To the extent our electricity facilities experience outages due to equipment failure, blackouts or constraints on the transmission system, delivery of power and associated revenues may be negatively affected. The Company's business continuity plans aim to enable EPCOR to continue providing critical services to customers in the event a crisis. The Company's emergency response protocols are designed to ensure EPCOR can expeditiously resume operations following a business interruption. Financial exposures associated with business interruption are partly mitigated through our insurance programs. Our ability to continuously operate and grow the business is dependent upon attracting, retaining and developing sufficient labor and management resources. As with most organizations, the Company is facing the demographic shift where a large number of employees are expected to retire over the next few years. Failure to secure sufficient qualified technical and leadership talent may impact EPCOR's operations or increase expenses. We believe that we employ good human resource practices and in 2016, we were named a top 70 employer in Alberta, by Mediacorp Canada Inc. We continue to monitor developments and review our human resource strategies so that we have an adequate supply of labor and management. EPCOR plans to diversify its utility infrastructure investments across investment types and North American geographies to reduce investment risk. The Company is planning to accomplish this through expansion into natural gas distribution and its pursuit of the Drainage transfer from the City to EPCOR. These types of utility businesses are new to EPCOR which introduces risk to the Company due to unfamiliarity with the associated operational, safety and regulatory risks in addition to the risks associated with integrating these businesses into EPCOR. EPCOR develops comprehensive integration plans and ensures that personnel with appropriate skills are in place to manage all of the various risks when integrating any new businesses into the Company. Water scarcity is the risk of inadequate raw water supply, particularly in the desert region of the Southwestern U.S. This is primarily related to drought conditions which could potentially impact EPCOR's water operations in Arizona, New Mexico and Texas. In Arizona in particular, a number of water management and supply augmentation strategies are employed to mitigate this risk including enacting some very progressive policies to protect groundwater supplies. While EPCOR is not obligated to demonstrate long term water adequacy for new customer growth, EPCOR actively manages its sources of water including replenishing reserves by injecting water into its wells when opportunity arises and working with regulators on rate rebalancing to mitigate the effects of declining consumption should it occur. Despite these efforts, continued drought in the Southwestern U.S. could result in legislated measures to further reduce customer water consumption, potentially impacting financial performance in Arizona and New Mexico. EPCOR sells electricity to RRO customers under a RRT. All electricity for the RRO customers is purchased in real time from the AESO in the spot market. Under the RRT, the amount of electricity to be economically hedged, the hedging method and the electricity selling prices to be charged to these customers is determined by the EPSP. Under the EPSP, the Company uses financial contracts to economically hedge the RRO requirements and incorporate the price into customer rates for the applicable month. Fixed volumes of electricity are economically hedged using financial contracts-for-differences up to 120 days in advance of the month in which the electricity (load) is consumed by the RRO customers. The volume of electricity economically hedged in advance is based on load (usage) forecasts for the consumption month. When consumption varies from forecast consumption patterns, EPCOR is exposed to prevailing market prices when the volume of electricity economically hedged is short of actual load requirements or greater than the actual load requirements (long). Exposure to variances in electricity volume can be exacerbated by other events such as unexpected generation plant outages and unusual weather patterns. Under contracts-for-differences the Company agrees to exchange, with a single creditworthy and adequately secured counterparty, the difference between the AESO electricity spot market price and the fixed contract price for a specified volume of electricity up to 120 days in advance of the consumption date, all in accordance with the EPSP. The contracts-for-differences are referenced to the AESO electricity spot price and any movement in the AESO price results in changes in the contract settlement amount. If the risks of the EPSP were to become untenable, EPCOR could test the market and potentially re-contract the procurement risk under an outsourcing arrangement at a certain cost that would likely increase procurement costs and reduce margins. The Company may enter into additional financial electricity purchase contracts outside the EPSP to further economically hedge the price of electricity. Our construction and development of water and wastewater treatment facilities and electricity transmission and distribution infrastructure and acquisition activities are subject to various engineering, construction, stakeholder, government and environmental risks. These risks can translate into performance issues, delays and cost overruns. Project delays may defer expected revenues and project cost overruns could make projects uneconomic. Many of the water and wastewater growth projects currently pursued by the Company require design and construction capabilities that are provided by third parties. In order to pursue these projects, strategic partnerships have been established with reputable firms that have an established track record of infrastructure design and construction. Should these partnerships dissolve or are not recognized by the market as a viable approach, the Company's growth plans could potentially be curtailed. We attempt to mitigate project risks by performing detailed project analysis and due diligence prior to and during construction or acquisition, and by entering into appropriate contracts for various services to be provided as required. Our ability to complete projects successfully depends upon numerous factors such as weather, civil disobedience, availability of skilled labor, strikes and regulatory matters. Weather can have a significant impact on our operations. Melting snow, freeze / thaw cycles and seasonal precipitation in the North Saskatchewan River watershed affect the quality of water entering our Edmonton water treatment plants and the resulting cost of purification. Weather variability and seasonality also impact the demand and supply of water and electricity in our respective businesses in Canada and the U.S. Extreme weather can cause damage to electricity distribution and transmission equipment and wires, temporarily disrupting the reliable supply of power to customers and can cause unpredictability in the demand for power. Unseasonal temperature changes can cause water main breaks temporarily disrupting the reliable supply of water to customers. Weather that varies significantly from historical norms can result in changes in the quantity of provincial power consumption. EPCOR procures power to service its RRO customers in advance of the consumption month and the quantity procured is based on historical weather and usage patterns. Unseasonal temperatures can cause a mismatch between the power procured in advance of the consumption month and actual customer usage, resulting in unexpected variances in income from the RRO business. Financial exposures associated with extreme weather are partly mitigated through our insurance programs. EPCOR's internally generated cash flows from operating activities do not provide sufficient capital to undertake or complete ongoing or future development, enhancement opportunities or acquisition plans and accordingly, the Company requires additional financing from time to time. The ability of the Company to arrange such financing will depend in part upon prevailing market conditions at the time and the Company's business performance. If the Company's revenues or cash flows decline, it may not have the capital necessary to undertake or complete all the initiatives. There can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or for other corporate purposes. Furthermore, if financing is available, there can be no assurance that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, prospects and financial condition. Further discussion is included in Liquidity and Capital Resources in this MD&A. The Company manages liquidity risk through regular monitoring of cash and currency requirements by preparing short-term and long-term cash flow forecasts and also by matching the maturity profiles of financial assets and liabilities to identify financing requirements. EPCOR's financial risks are governed by a Board-approved financial exposure management policy, which is administered by EPCOR's Treasurer. Counterparty and credit risk is the possible financial loss associated with the ability of counterparties to satisfy their contractual obligations to EPCOR, including payment and performance including the long-term loans receivable from Capital Power. We manage credit risk and limit exposures through our credit policies and procedures. These include an established credit review, rating and monitoring process, specific terms and limits, appropriate allowance provisioning and use of credit mitigation strategies, including collateral arrangements. EPCOR's credit risks are governed by a Board-approved counterparty credit risk management policy, which is administered by EPCOR's treasury function. Significant reliance is placed on the capacity of Capital Power to honor its remaining back-to-back debt obligations with EPCOR. Should Capital Power fail to satisfy these obligations, EPCOR's capacity to satisfy its debt obligations would be reduced and would need to be satisfied by other means. The back-to-back debt obligations may be called for repayment by EPCOR at any time now that the principal outstanding is less than $200 million and the repayment must occur within 180 days of notice. Capital Power has indemnified EPCOR for any losses arising from its inability to discharge its liabilities, including any amounts owing to EPCOR in relation to the long-term loans receivable. Exposure to credit risk for residential RRO customers and commercial customers under default electricity supply rates are generally limited to amounts due from the customers for electricity consumed but not yet paid for. This portfolio is reasonably well diversified with no significant credit concentrations. Historically, credit losses in these customer segments have not been significant and depend in large part on the strength of the economy and the ability of the customers to effectively manage their financial affairs through economic cycles and competitive pressures. While electricity is considered an essential service, EPCOR may experience credit losses in the future should economic conditions deteriorate. EPCOR's exposure to RRO and default customer credit risk, which is primarily the risk of non-payment for electricity consumed by these end-use customers, is summarized below. Exposures represent the accounts receivable value for this portfolio. The year-over-year decrease in exposure relates to lower customer rates and consumption. Exposures to credit risk in our rate-regulated and non-rated-regulated water businesses are generally limited to amounts due from the customers for water consumed and wastewater discharged but not yet paid for, as well as amounts for water management services provided under contracts to municipal and industrial customers. This portfolio is reasonably well diversified with no significant credit concentrations. While water is considered an essential service, EPCOR may experience credit losses in the future should economic conditions deteriorate. EPCOR's exposure to rate-regulated and non-rate-regulated customer credit risk, which is primarily the risk of non-payment for water consumed by these end-use customers, is summarized below. Exposures represent a 60-day potential accounts receivable value for this portfolio. The customer consumption data used to bill utility customers is voluminous plus the sources and types of customer billing data are varied, requiring large, complex systems to process customer billings. In addition, the Company relies on third parties to provide customer meter data in certain circumstances and to produce bills for its U.S. customers. All of this contributes to the potential for billing errors caused by poor customer consumption data quality, billing system computational errors, incorrect customer rates being used or transactions and adjustments being applied incorrectly to customer accounts. The Company applies numerous manual and automated controls to ensure the quality of customer billings including a routine to identify various exceptions in the electricity meter data used to produce bills. The Company is exposed to foreign exchange risk on foreign currency denominated transactions, firm commitments, monetary assets and liabilities denominated in a foreign currency and on its net investments in foreign entities. The Company's financial exposure management policy attempts to minimize economic and material transactional exposures arising from movements in the Canadian dollar relative to the U.S. dollar or other foreign currencies. The Company's direct exposure to foreign exchange risk arises on capital expenditure commitments denominated in U.S. dollars or other foreign currencies and U.S. operations. The Company coordinates and manages foreign exchange risk centrally, by identifying opportunities for naturally occurring opposite movements and then dealing with any material residual foreign exchange risks. The Company's exposure to foreign exchange risk on its investment in foreign entities is partially mitigated by foreign-denominated financing. The Company may use foreign currency forward contracts to fix the functional currency of its non-functional currency cash flows thereby reducing its anticipated U.S. dollar denominated transactional exposure. The Company looks to limit foreign currency exposures as a percentage of estimated future cash flows. Certain conflicts of interest could arise as a result of EPCOR's relationship with the City, EPCOR's sole common shareholder and regulator for water and wastewater utility rates in Edmonton. The following factors could materially adversely impact EPCOR's business, prospects, financial condition, results of operations or cash flows: fluctuations in interest rates, product supply and demand, market competition, risks associated with technology, general economic and business conditions, EPCOR's ability to make capital investments and the amounts of capital investments, risks associated with existing and potential future lawsuits and other regulations, assessments and audits (including income tax) against EPCOR and its subsidiaries, political and economic conditions in the geographic regions in which EPCOR and its subsidiaries operate, difficulty in obtaining necessary regulatory approvals, a significant decline in EPCOR's reputation and such other risks and uncertainties described from time to time in EPCOR's reports and filings with the Canadian Securities authorities. The following table outlines our estimated sensitivity to specific risk factors as at December 31, 2016. Each sensitivity factor provides a range of outcomes assuming all other factors are held constant and current risk management strategies are in place. Under normal circumstances, such sensitivity factors will not be held constant but rather, will change at the same time as other factors are changing. In addition, the degree of sensitivity to each factor will change as the Company's mix of assets and operations subject to these factors changes. The Company is not involved in any material litigation at this time. For purposes of certain Canadian securities regulations, EPCOR is a venture issuer. As such, it is exempt from certain of the requirements of National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The Chief Executive Officer and Chief Financial Officer have reviewed the annual information form, annual financial statements and annual MD&A, for the year ended December 31, 2016. Based on their knowledge and exercise of reasonable diligence, they have concluded that these materials fairly present in all material respects the financial condition, results of operations and cash flows of the Company for the periods presented. A number of new standards, amendments to standards and interpretations have been issued by the IASB and the International Financial Reporting Interpretations Committee the application of which is effective for periods beginning on or after January 1, 2017. Those which may be relevant to the Company and may impact the accounting policies of the Company are set out below. The Company does not plan to adopt these standards early. The extent of the impact of adoption of the standards has not yet been determined. IFRS 9 - Financial Instruments (IFRS 9), which replaces IAS 39 - Financial Instruments: Recognition and Measurement, eliminates the existing classification of financial assets and requires financial assets to be measured based on the business model in which they are held and the characteristics of their contractual cash flows. Gains and losses on re-measurement of financial assets at fair value will be recognized in profit or loss, except for an investment in an equity instrument which is not held-for-trading. Changes in fair value attributable to changes in credit risk of financial liabilities measured under the fair value option will be recognized in other comprehensive income with the remainder of the change recognized in profit or loss unless an accounting mismatch in profit or loss occurs at which time the entire change in fair value will be recognized in profit or loss. Derivative liabilities that are linked to and must be settled by delivery of an unquoted equity instrument must be measured at fair value. The impairment model has also been amended by introducing a new 'expected credit loss' model for calculating impairment, and new general hedge accounting requirements. The effective date for implementation of IFRS 9 has been set for annual periods beginning on or after January 1, 2018. IFRS 15 - Revenue from Contracts with Customers (IFRS 15), which replaces IAS 11 - Construction Contracts and IAS 18 - Revenue and related interpretations, is effective for annual periods commencing on or after January 1, 2018. IFRS 15 introduces a new single revenue recognition model for contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and / or timing of revenue recognized. The requirements of the standard also apply to the recognition and measurement of gains and losses on sale of some non-financial assets that are not part of the entity's ordinary activities. IFRS 16 - Leases (IFRS 16), which replaces IAS 17 - Leases (IAS 17), is effective for annual periods commencing on or after January 1, 2019. IFRS 16 combines the existing dual model of operating and finance leases in IAS 17 into a single lessee model. Under the new single lessee model, a lessee will recognize lease assets and lease liabilities on the statement of financial position initially measured at the present value of unavoidable lease payments. IFRS 16 will also cause expenses to be higher at the beginning and lower towards the end of a lease, even when payments are consistent throughout the term. Leases for duration of twelve months or less and leases of low value assets are exempted from recognition on the statement of financial position. Lessors will continue with a dual lease classification model and the classification will determine how and when a lessor will recognize lease revenue and what assets will be recorded. In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the financial statements. Due to the lag time between customer electricity consumption and receipt of final billing consumption information from the load settlement agents, the Company must use estimates for determining the amount of electricity consumed but not yet billed. These estimates affect accrued revenues and accrued electricity costs of the Energy Services segment. There are a number of variables and judgments required in the computation of these significant estimates, and the underlying electricity settlement processes within EPCOR and the Alberta electric systems are complex. Such variables and judgments include the number of unbilled sites, and the amount of and rate classification of the unbilled electricity consumed. Owing to the factors above and the statutory delays in final load settlement determinations and information, adjustments to previous estimates could be material. Estimates for unbilled consumption averaged approximately $51 million at the end of each month in 2016 (2015 - $53 million). These estimates varied from $35 million to $68 million (2015 - $42 million to $67 million). Adjustments of estimated revenues to actual billings were not higher than $5 million per month in 2016 (2015 - $6 million). We are required to estimate the fair value of certain assets or obligations for determining the valuation of certain financial instruments, asset impairments, asset retirement obligations and purchase price allocations for business combinations, and for determining certain disclosures. Significant judgment is applied in the determination of fair values including the choice of discount rates, estimating future cash flows, and determining goodwill. Following are the descriptions of the key fair value methodologies relevant for 2016. Fair values of financial instruments are based on quoted market prices when these instruments are traded in active markets. In illiquid or inactive markets, the Company uses appropriate price modeling to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows and discount rates. The Company reviews the valuation of long-lived assets subject to amortization when events or changes in circumstances may indicate or cause a long-lived asset's carrying amount to exceed the total undiscounted future cash flows expected from its use and eventual disposition. An impairment loss, if any, will be recorded as the excess of the carrying amount of the asset over its fair value, measured by either market value, if available, or estimated by calculating the present value of expected future cash flows related to the asset. Estimates of fair value for long-lived asset impairments are mainly based on depreciable replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions, including the selection of an appropriate discount rate. The cash flow estimates will vary with the circumstances of the particular assets or reporting unit and will primarily be based on the lives of the assets, revenues and expenses, including inflation, and required capital expenditures. EPCOR follows the asset and liability method of accounting for income taxes. Income taxes are determined based on estimates of our current taxes and estimates of deferred taxes resulting from temporary differences between the carrying values of assets and liabilities in the financial statements and their tax values. Deferred tax assets are assessed and significant judgment is applied to determine the probability that they will be recovered from future taxable income. For example, in estimating future taxable income, judgment is applied in determining the Company's most likely course of action and the associated revenues and expenses. To the extent recovery is not probable a deferred tax asset is not recognized. Estimates of the provision for income taxes and deferred tax assets and liabilities might vary from actual amounts incurred. Estimated fair values and useful lives are used in determining potential impairments for each long-lived asset, which will vary with each asset and market conditions at the particular time. Similarly, income taxes will vary with taxable income and, under certain conditions, with fair values of assets and liabilities. Accordingly, it is not possible to provide a reasonable quantification of the range of these estimates that would be meaningful to readers. Although the current condition of the economy has not impacted our methods of estimating accounting values, it has impacted the inputs in those determinations and the resulting values. Future cash flow estimates for assessing long-lived assets (cash generating units or CGUs) for impairment were updated to reflect any increased uncertainties of recoverability. The assessments did not result in any impairment losses because a large portion of the Company's long-lived assets are subject to rate-regulation. Similarly, the assessment of the useful lives of our long-lived assets did not change since many of our distribution and transmission assets and water assets are amortized based on rates approved by the applicable regulator. Our valuation models for estimating the fair value of long-lived asset impairments depend partly on discount rates which were updated to reflect changes in credit spreads and market volatility. Our methods for determining the allowance for doubtful accounts are based on historical rates of bad debts in relation to the aged accounts receivable balances by customer group for RRO and default customer bases. These analyses did not reveal any significant changes in our assessment of the recoverability of accounts receivable at December 31, 2016. For the three and twelve months ended December 31, 2016, the Company's transactions in other comprehensive income included the following: Events for the past eight quarters compared to the same quarter of the prior year that have significantly impacted net income included: The comparative information in the line of business information have been reclassified, where applicable, to conform to current year presentation. Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target", and "expect" or similar words suggest future outcomes. The purpose of forward-looking information is to provide investors with management's assessment of future plans and possible outcomes and may not be appropriate for other purposes. Material forward-looking information within this MD&A, including related material factors or assumptions and risk factors, are noted in the table below: The following table provides a comparison between actual results and future-oriented-financial information previously disclosed: Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties, which could cause actual results to differ from expectations and are discussed in the Risk Factors and Risk Management section above. Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Except as required by law, EPCOR disclaims any intention and assumes no obligation to update any forward-looking statement even if new information becomes available, as a result of future events or for any other reason. Additional information relating to EPCOR, including the Company's 2016 Annual Information Form, is available on SEDAR at www.sedar.com.
News Article | February 21, 2017
System Innovators (SI), a division of N. Harris Computer Corporation, is pleased to announce the general availability of iNovah EMV Direct, a processor agnostic and secure Europay, MasterCard and Visa (EMV) chip credit card payment processing solution for governments. Built with government agency needs in mind, the flexible and scalable solution combines SI's flagship point-of-sale centralized cashiering and enterprise revenue management (ERM) solution, iNovah, with the ability to accept EMV chip card transactions from multiple credit card processors. EMV Direct is seamlessly integrated with iNovah which allows payment amounts to be automatically sent to the credit card terminal and securely encrypts customer data to mitigate clients' risk of card-present fraud utilizing end to end encryption technologies. With this solution, city and county cashiers are able to remain in iNovah, a centralized cashiering solution, with no need to manually enter in credit card information reducing customer payment times, eliminating errors and manual entry of payment data. With the nationwide EMV liability shift, cities and counties who implement iNovah EMV Direct will realize immediate benefits with increased fraud protection, greater operational efficiency, secure transactions and the ability to route transactions directly to their processor of choice including First Data, Chase Paymentech, Vantiv, Global Payments (Canada), and Moneris (Canada). iNovah EMV Direct improves citizen – government relations by expediting the payment collection process with a one-stop-shop experience as well as permits government customers the freedom to use multiple payment methods as the solution supports payment from cards embedded with chip and PIN technology, contactless payments (Visa payWave, MasterCard PayPass), mobile digital wallet (Android Pay, Apple Pay), debit, credit and cash payments. For more information on iNovah EMV Direct please contact firstname.lastname@example.org or visit http://www.systeminnovators.com/en/solutions/emv_direct/. Follow the conversation on Facebook and Twitter. System Innovators is a division of N. Harris Computer Corporation and a leading provider of financial management and customer information system software solutions. Enterprise revenue management offerings include iNovah ERM, a fully configurable PCI compliant payment collection, cashiering and financial reporting solutions. Specializing in citizen self-service, revenue management, auditing and financial reporting, System Innovators’ products integrate seamlessly with hundreds of websites, deposit banks, payment card gateway providers, and host and financial systems. For more information, please visit http://www.systeminnovators.com.
News Article | February 20, 2017
FRAMINGHAM, Mass.--(BUSINESS WIRE)--A new update to the International Data Corporation (IDC) Worldwide Semiannual Public Cloud Services Spending Guide shows that worldwide spending on public cloud services and infrastructure will reach $122.5 billion in 2017, an increase of 24.4% over 2016. Over the 2015-2020 forecast period, overall public cloud spending will experience a 21.5% compound annual growth rate (CAGR) – nearly seven times the rate of overall IT spending growth. By 2020, IDC forecasts public cloud spending will reach $203.4 billion worldwide. Software as a Service (SaaS) will remain the dominant cloud computing type, capturing nearly two thirds of all public cloud spending in 2017 and roughly 60% in 2020. SaaS spending, which is comprised of applications and system infrastructure software (SIS), will in turn be dominated by applications purchases, which will make up more than half of all public cloud spending throughout the forecast period. However, spending on Infrastructure as a Service (IaaS) and Platform as a Service (PaaS) will grow at much faster rates than SaaS with five-year CAGRs of 30.1% and 32.2%, respectively. "In 2017, discrete manufacturing, professional services, and banking will lead the pack in global spending on public cloud services as they look for greater scalability, higher performance, and faster access to new technologies," said Eileen Smith, program director, Customer Insights and Analysis. "Combined, these three industries will account for one third of worldwide public cloud services spending, or $41.2 billion." The industries that will see the fastest growth in public cloud spending over the five-year forecast period are professional services (23.9% CAGR), retail (22.8% CAGR), media (22.5% CAGR), and telecommunications (22.1% CAGR). It is worth noting, however, that 18 of the 20 industries included in the Spending Guide will experience five-year CAGRs greater than 20%. In terms of company size, nearly half of all public cloud spending will come from very large businesses (those with more than 1,000 employees) while medium-sized businesses (100-499 employees) will deliver more than 20% throughout the forecast. Large businesses (500-999 employees) will see the fastest growth with a five-year CAGR of 23.2%. While purchase priorities vary somewhat depending on company size, the leading product categories include customer relationship management (CRM) and enterprise resource management (ERM) applications in addition to server and storage hardware. On a geographic basis, the United States will be the largest market for public cloud services, generating more than 60% of total worldwide revenues throughout the forecast. Western Europe and Asia/Pacific (excluding Japan)(APeJ) will be the second and third largest regions with 2017 spending levels of $24.1 billion and $9.5 billion, respectively. APeJ and Latin America will experience the fastest spending growth over the forecast period with CAGRs of 28.0% and 26.6%, respectively. However, seven of the eight regions are forecast to experience CAGRs greater than 20% over the next five years with the United States seeing the slowest growth at 19.9%. "In Western Europe, the public cloud market will grow at a healthy 23.2% CAGR over the forecast period and utilities, insurance, and professional services industries will be the most dynamic market spaces," said Serena Da Rold, senior research manager, Customer Insights and Analysis. "European companies have been slower in the adoption of cloud when compared to their U.S. counterparts, but now the market is maturing and it is the right time for cloud providers to target and capture the untapped segments." "As cloud adoption expands over the next four years, what clouds are and what they can do will evolve dramatically – in several important ways. The cloud will become more distributed (through Internet of Things edge services and multicloud services), more trusted, more intelligent, more industry and workload specialized, and more channel mediated. As the cloud evolves these important new capabilities – what IDC calls 'Cloud 2.0' – the use cases for the cloud will dramatically expand," added Frank Gens, senior vice president and chief analyst at IDC. The Worldwide Semiannual Public Cloud Services Spending Guide quantifies public cloud computing purchases by cloud type for 20 industries and five company sizes across eight regions and 47 countries. Unlike any other research in the industry, the comprehensive spending guide was designed to help IT decision makers to clearly understand the industry-specific scope and direction of public cloud services spending today and over the next five years. About IDC Spending Guides IDC's Spending Guides provide a granular view of key technology markets from a regional, vertical industry, use case, buyer, and technology perspective. The spending guides are delivered via pivot table format or custom query tool, allowing the user to easily extract meaningful information about each market by viewing data trends and relationships. For more information about IDC's Spending Guides, please contact Monika Kumar at email@example.com. About IDC International Data Corporation (IDC) is the premier global provider of market intelligence, advisory services, and events for the information technology, telecommunications, and consumer technology markets. With more than 1,100 analysts worldwide, IDC offers global, regional, and local expertise on technology and industry opportunities and trends in over 110 countries. IDC's analysis and insight helps IT professionals, business executives, and the investment community to make fact-based technology decisions and to achieve their key business objectives. Founded in 1964, IDC is a wholly-owned subsidiary of International Data Group (IDG), the world's leading media, data, and marketing services company. To learn more about IDC, please visit www.idc.com. Follow IDC on Twitter at @IDC.
News Article | February 28, 2017
System Innovators (SI), a division of N. Harris Computer Corporation, is pleased to announce that Texas’ fifth largest city and the 16th largest city in the US the City of Fort Worth, has selected SI’s iNovah Enterprise Revenue Management (ERM) and Centralized Cashiering solution. iNovah will replace the City’s non-integrated legacy cashiering solution within the Department of Financial Management Services (FMS) and select City departments to standardize payment processing and cash receipting while streamlining citizen facing payment processes. The Department of Financial Management Services processes thousands of payments annually including city wide billing and license renewals through cash, check and credit card payments on behalf of several city departments through a non-integrated cashiering solution. Utilizing a non-integrated cashiering solution for multiple city department’s risks duplication of receipting, reporting and reconciliation as well as human error and lost time. “We wanted to ensure we selected a centralized cashiering solution that would be right for our enterprise now and over the long term. System Innovators presented us with a business case that made us confident to move forward with iNovah ERM and Centralized Cashiering solution.” stated Aaron Bovos, Chief Financial Officer for the City of Fort Worth. The City will modernize its use of multiple merchant card devices, customer account systems and cash drawers each dedicated to one or more types of payments with a fully integrated City-Wide cashiering solution to gain economies of scale in the management and operation. “System Innovators is pleased to provide the City of Fort Worth with the leading cashiering solution for government.” stated Greg Whitnell, Vice President of Sales and Marketing for System Innovators, “iNovah will improve the City’s cash control processes, provide a single point of reporting, reconciling and audit for all revenues as well as provide improved customer service in billing and payment processing.” iNovahs’ configurability and ability to integrate to other account receivable/billing host systems allows the centralized cashiering and enterprise revenue management solution to be readily adopted across other City departments including Parks, Courts, Library, and Police. System Innovators looks forward to working closely with the City of Fort Worth to implement iNovah. System Innovators is a division of N. Harris Computer Corporation and a leading provider of financial management and customer information system software solutions. Enterprise revenue management offerings include iNovah ERM, a fully configurable PCI compliant payment collection, cashiering and financial reporting solutions. Specializing in citizen self-service, revenue management, auditing and financial reporting, System Innovators’ products integrate seamlessly with hundreds of websites, deposit banks, payment card gateway providers, and host and financial systems. For more information, please visit http://www.systeminnovators.com.
News Article | February 24, 2017
OLDWICK, N.J.--(BUSINESS WIRE)--A.M. Best has affirmed the Financial Strength Rating (FSR) of A++ (Superior) and the Long-Term Issuer Credit Ratings (Long-Term ICR) of “aaa” of United Services Automobile Association (USAA) and its property/casualty and life/health subsidiaries. Concurrently, A.M. Best has affirmed the Long-Term Issue Credit Rating (Long-Term IR) of “aaa” on the medium-term note program and the senior unsecured medium-term notes and the rating of AMB-1+ on the commercial paper program of USAA Capital Corporation. A.M. Best has also assigned a Long-Term IR of “aaa” to USAA Capital Corporation’s newly issued $350 million senior unsecured floating rate bonds. The outlook for all Credit Ratings (ratings) is stable, with the exception of the commercial paper, which does not have an outlook. Both companies are domiciled in San Antonio, TX. (See below for a detailed listing of the companies and ratings.) The rating affirmations reflect USAA’s superior risk-adjusted capitalization and strong operating results through focused business and financial strategies. USAA maintains diversified sources of earnings and strong enterprise risk management (ERM) with a full range of financial products and services to its membership of military and ex-military personnel and their dependents. USAA’s low cost structure, high customer retention, effective use of technology and exceptional customer service capabilities have enabled it to build a sustainable competitive advantage in the personal lines sector. As a result of these strengths, USAA has built a sizeable market position, especially in the property/casualty segment, as the nation’s fifth-largest private passenger auto and fifth-largest homeowners’ policy provider, based on A.M. Best 2015 industry direct premium data. In addition, USAA maintains a relatively conservative investment strategy, which has enabled it to experience favorable investment returns even during times of significant market turmoil and record low interest rates. As part of its ERM strategy, USAA has developed strong catastrophe management and a sound reinsurance program that has preserved the capital and financial security of its membership through years of significant catastrophe activity, and has also implemented a series of initiatives to address recent auto results. Modestly offsetting these positive rating factors is USAA’s exposure to frequent and severe weather-related events. This exposure was demonstrated in 2016 as USAA experienced its worst catastrophe loss year in its history for both losses and claim counts due to a series of hail storms in Texas and Colorado. In addition, an uptick in frequency and severity of automobile losses as a result of macroeconomic factors also pressured USAA’s loss ratio in 2016. The ratings of USAA Life Insurance Company and its subsidiary, USAA Life Insurance Company of New York, together referred to as USAA Life, are based on its superior stand-alone risk-adjusted capitalization, favorable operating results and a diversified product profile, while supporting its parent’s strategy of facilitating the financial security of its members through a full range of financial products and services. The ratings also reflect the financial strength of USAA, as well as the considerable benefits associated with the depth of USAA’s relationship with its military affinity group. USAA Life serves as the life insurance arm of USAA and benefits from parental resources, including advanced technology to support its life, annuity and health operations. Rating considerations also include strong liquidity coverage ratios, along with well-integrated ERM practices to monitor and mitigate stress events throughout the organization. Partially offsetting rating factors include the challenges associated with balancing the company’s earnings/reserves mix between ordinary life and annuities, maintaining targeted spreads on its annuity business in the prolonged low interest rate environment and the recent downward credit migration within its investment grade fixed income portfolio. The FSR of A++ (Superior) and the Long-Term ICRs of “aaa” have been affirmed with a stable outlook for United Services Automobile Association and its following property/casualty and life/health subsidiaries: The following Long-Term IRs have been affirmed: -- “aaa” on the medium-term note program -- “aaa” on $350 million 2.125% senior unsecured bonds, due 2019 -- “aaa” on $400 million 2.450% senior unsecured bonds, due 2020 -- AMB-1+ on the commercial paper program The following Long-Term IR has been assigned: This press release relates to Credit Ratings that have been published on A.M. Best’s website. For all rating information relating to the release and pertinent disclosures, including details of the office responsible for issuing each of the individual ratings referenced in this release, please see A.M. Best’s Recent Rating Activity web page. For additional information regarding the use and limitations of Credit Rating opinions, please view Understanding Best’s Credit Ratings. A.M. Best is the world’s oldest and most authoritative insurance rating and information source. For more information, visit www.ambest.com. Copyright © 2017 by A.M. Best Rating Services, Inc. and/or its subsidiaries. ALL RIGHTS RESERVED.
News Article | February 22, 2017
SPOKANE, WA--(Marketwired - February 22, 2017) - Avista Corp. ( : AVA) today reported net income attributable to Avista Corp. shareholders of $137.2 million, or $2.15 per diluted share, for the year ended Dec. 31, 2016, compared to $123.2 million, or $1.97 per diluted share for the year ended Dec. 31, 2015. Results for 2015 included $5.1 million, or $0.08 per diluted share, related to discontinued operations, which resulted from the sale of Ecova in 2014. For the fourth quarter of 2016, net income attributable to Avista Corp. shareholders was $40.1 million or $0.62 per diluted share, compared to $38.5 million or $0.61 per diluted share for the fourth quarter of 2015. Results for the fourth quarter of 2015 included $4.7 million, or $0.07 per diluted share related to discontinued operations. "We had a great year in 2016. We saw increased earnings at Avista Utilities compared to 2015 due to increased electric and natural gas gross margin, which was partially offset by increased operating expenses, depreciation and interest expense. Our strong operational performance in 2016 resulted in continued reliable service for our customers and high customer satisfaction ratings. We also continued making capital investments in our utility infrastructure, which we view as critical for the safety and reliability of our system and to meet the needs of our customers into the future. In addition, we strengthened our commitment to our communities through further development of innovative technologies in our service area," said Scott Morris, chairman, president and chief executive officer of Avista Corp. "As we look to 2017, our earnings will be challenged due to the rate order we received in December from the Commission in Washington, which denied our requests for increased electric and natural gas rates. We were surprised and very disappointed in this order, and as a response we have filed a petition for reconsideration and alternately for rehearing of our 2016 general rate cases. The Commission has indicated it expects to enter an order no later than March 16, 2017 resolving our petition. "If we are not successful in obtaining rates that are fair to both customers and the company, we expect the current order will result in significant regulatory timing lag, which was reduced in recent years through regulatory orders that provided for the timely recovery of costs. We believe we should continue investing the necessary capital to maintain a safe and reliable system and focus on managing our operating expenses. The Commission did not disallow any of our capital projects, and we believe the costs associated with these projects will be recovered in future cases. "Alaska Electric Light and Power Company (AEL&P) had another successful year and exceeded its earnings target for the year. An interim rate increase went into effect in November and a permanent rate increase, if approved, could take effect no later than February 2018. "We are initiating our 2017 earnings guidance with a consolidated range of $1.80 to $2.00 per diluted share. The Washington rate order negatively impacted our 2017 earnings guidance in the range of $0.20 to $0.30 per diluted share. However, I believe we are still well-positioned to continue our long-term earnings growth of 4 percent to 5 percent," Morris said. Summary Results: Avista Corp.'s results for the fourth quarter of 2016 and the year ended Dec. 31, 2016 (year-to-date) as compared to the respective periods in 2015 are presented in the table below (dollars in thousands, except per-share data): The table below presents the change in net income attributable to Avista Corp. shareholders and diluted earnings per share for the fourth quarter of 2016 and the year ended Dec. 31, 2016 as compared to the respective periods in 2015 and the various factors that caused such change (dollars in thousands, except per-share data): (a) The tax impact of each line item was calculated using Avista Corp.'s statutory tax rate (federal and state combined) of 36.7 percent. (b) Electric gross margin (operating revenues less resource costs) increased for both the fourth quarter and year-to-date primarily due to the following: (c) Natural gas gross margin (operating revenues less resource costs) increased for both the fourth quarter and year-to-date primarily due to the following: (d) Other operating expenses for the fourth quarter and year-to-date 2016 increased due to an increase in medical costs, electric generation operating and maintenance expenses, natural gas distribution expenses and other postretirement benefit expenses. (e) Depreciation and amortization increased for the fourth quarter and year-to-date 2016 due to additions to utility plant. (f) Interest expense increased for the fourth quarter and year-to-date 2016 due to additional long-term debt being outstanding during 2016 as compared to 2015 and partially due to an increase in the overall interest rate. (g) Other for the year-to-date 2016 increased primarily due to a decrease in the allowance for funds used during construction (AFUDC) and was partially offset by an increase in interest income for the fourth quarter and year-to-date. (h) During the fourth quarter of 2016 our effective tax rate was 36.9 percent compared to 37.2 percent for the fourth quarter of 2015 and it was 36.3 percent for the full year 2016 and 2015. (i) Other businesses' earnings decreased primarily due to an increase in losses on investments from initial organization costs and management fees associated with our investment in a private equity fund of strategic utility partners, as well as an impairment recorded on a building we own. This was partially offset by a slight decrease in corporate costs (including costs associated with exploring strategic opportunities) and a slight increase in net income at METALfx for the year-to-date. Non-Generally Accepted Accounting Principles (Non-GAAP) Financial Measures The tables above and below include electric gross margin and natural gas gross margin, two financial measures that are considered "non-GAAP financial measures." Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles (GAAP). The presentation of electric gross margin and natural gas gross margin for Avista Utilities is intended to supplement an understanding of Avista Utilities' operating performance. We use these measures to determine whether the appropriate amount of revenue is being collected from customers to allow for the recovery of energy resource costs and operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. We present electric and natural gas gross margin separately above and below since each business has different cost sources, cost recovery mechanisms and jurisdictions. These measures are not intended to replace income from operations as determined in accordance with GAAP as an indicator of operating performance. The calculations of electric and natural gas gross margins are presented below. The following table presents our operating revenues, resource costs and resulting gross margin (pre-tax and after-tax) for the fourth quarter and the year ended Dec. 31, 2016 and 2015, respectively (dollars in thousands): (a) Income taxes were calculated using Avista Corp.'s statutory tax rate (federal and state combined) of 36.7 percent. Avista Corp. has a $400.0 million committed line of credit that expires in April 2021. As of Dec. 31, 2016, there were $120.0 million of cash borrowings and $34.4 million in letters of credit outstanding, leaving $245.6 million of available liquidity under this committed line of credit. AEL&P has a $25.0 million committed line of credit that expires in November 2019. As of Dec. 31, 2016, there were no borrowings and no letters of credit outstanding under this line of credit. In 2016, we issued 1.6 million shares of common stock for total net proceeds of $65.3 million under our sales agency agreements. We have 2.2 million shares remaining to be issued under our sales agency agreements. We also issued 0.2 million shares of common stock for total net proceeds of $1.7 million under our employee plans. In December 2016, we issued and sold $175.0 million of first mortgage bonds due in 2051. In the second half of 2017, we expect to issue approximately $110.0 million of long-term debt and up to $70.0 million of common stock in order to fund planned capital expenditures and maintain an appropriate capital structure. Avista Utilities' capital expenditures were $390.7 million for 2016, and we expect Avista Utilities' capital expenditures to be about $405 million for 2017. AEL&P's capital expenditures were $16.0 million for 2016, and we expect AEL&P's capital expenditures to be approximately $7 million for 2017. Avista Corp. is initiating its 2017 guidance for consolidated earnings to be in the range of $1.80 to $2.00 per diluted share. We expect Avista Utilities to contribute in the range of $1.71 to $1.85 per diluted share for 2017. As a change from earnings guidance in prior years, the midpoint of our Avista Utilities guidance range for 2017 includes $0.07 of expense under the ERM, which is within the 90 percent customers/10 percent shareholders sharing band. The impacts of the ERM are included in the midpoint of our guidance for 2017 as power supply costs were not reset in the Washington order for 2017. Our outlook for Avista Utilities assumes, among other variables, normal precipitation, temperatures and hydroelectric generation for the remainder of the year. Our 2017 Avista Utilities earnings guidance range continues to encompass unrecovered structural costs estimated to reduce the return on equity by 70 to 90 basis points. In addition, our 2017 guidance range includes regulatory timing lag directly associated with the Washington jurisdiction and resulting from the 2016 order estimated to reduce the return on equity by 100 to 120 basis points. This results in an expected return on equity range for Avista Utilities of 7.4 percent to 7.8 percent in 2017. We will continue to strive to reduce this timing lag and more closely align our earned returns with those authorized by the 2019-2020 time period. For 2017, we expect AEL&P to contribute in the range of $0.10 to $0.14 per diluted share. Our outlook for AEL&P assumes, among other variables, normal precipitation and hydroelectric generation for the remainder of the year. We expect the other businesses to be between a loss of $0.01 and a gain of $0.01 per diluted share, which includes costs associated with exploring strategic opportunities. Our guidance generally includes only normal operating conditions and does not include unusual items such as settlement transactions or acquisitions/dispositions until the effects are known and certain. NOTE: We will host a conference call with financial analysts and investors on Feb. 22, 2017, at 10:30 a.m. ET to discuss this news release. The call will be available at (888) 771-4371, confirmation number: 44214190. A simultaneous webcast of the call will be available on our website, www.avistacorp.com. A replay of the conference call will be available through March 1, 2017. Call (888) 843-7419, pass code 44214190#, to listen to the replay. Avista Corp. is an energy company involved in the production, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is our operating division that provides electric service to 377,000 customers and natural gas to 340,000 customers. Our service territory covers 30,000 square miles in eastern Washington, northern Idaho and parts of southern and eastern Oregon, with a population of 1.6 million. AERC is an Avista subsidiary that, through its subsidiary AEL&P, provides retail electric service to 17,000 customers in the city and borough of Juneau, Alaska. Our stock is traded under the ticker symbol "AVA". For more information about Avista, please visit www.avistacorp.com. Avista Corp. and the Avista Corp. logo are trademarks of Avista Corporation. This news release contains forward-looking statements, including statements regarding our current expectations for future financial performance and cash flows, capital expenditures, financing plans, our current plans or objectives for future operations and other factors, which may affect the company in the future. Such statements are subject to a variety of risks, uncertainties and other factors, most of which are beyond our control and many of which could have a significant impact on our operations, results of operations, financial condition or cash flows which could cause actual results to differ materially from those anticipated in such statements. The following are among the important factors that could cause actual results to differ materially from the forward-looking statements: weather conditions (temperatures, precipitation levels and wind patterns), including those from long-term climate change, which affect both energy demand and electric generating capability, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar effects on supply and demand in the wholesale energy markets; our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy; changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers; changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities; deterioration in the creditworthiness of our customers; the outcome of legal proceedings and other contingencies; economic conditions in our service areas, including the economy's effects on customer demand for utility services; declining energy demand related to customer energy efficiency and/or conservation measures; state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, financing costs and commodity costs and regulatory discretion over authorized return on investment; possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions; the effect on any or all of the foregoing, resulting from changes in general economic or political factors; volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by counterparties in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities; default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy; potential environmental regulations affecting our ability to utilize or resulting in the obsolescence of our power supply resources; severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services; explosions, fires, accidents, mechanical breakdowns or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power; wildfires, including those caused by our transmission or electric distribution systems that may result in public injuries or property damage; public injuries or damage arising from or allegedly arising from our operations; blackouts or disruptions of interconnected transmission systems (the regional power grid); terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems; work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees; increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance; delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities; increasing health care costs and cost of health insurance provided to our employees and retirees; third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel receptacles within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines; the loss of key suppliers for materials or services or disruptions to the supply chain; adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel); changing river regulation at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream; compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs; the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels; cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation; disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service; changes in costs that impede our ability to effectively implement new information technology systems or to operate and maintain our current production technology; changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security risk; insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems; growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites; potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources, loss of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price; changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain; non-regulated activities may increase earnings volatility; changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters; the potential effects of legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes; political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities; wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements; failure to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business; policy and/or legislative changes resulting from the new presidential administration in various regulated areas, including, but not limited to, potential tax reform, environmental regulation and healthcare regulations; and the risk of municipalization in any of our service territories. For a further discussion of these factors and other important factors, please refer to our Annual Report on Form 10-K for the year ended Dec. 31, 2016. The forward-looking statements contained in this news release speak only as of the date hereof. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on our business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.
Erm | Date: 2013-04-24
The folding assembly box comprises: vertical corner hinge frames that can be folded out at an angle forming each corners of the box, and can be hinged in the opposite direction thereof; first lower and upper horizontal frames that are placed to connect each of the upper ends and lower ends of the corresponding vertical corner hinge frames; vertical middle hinge frames that are placed in the middle of the corresponding vertical corner hinge frames, fold out with each of the vertical corner hinge frames, and can be hinged in the opposite direction thereof; second upper and lower horizontal frames that are placed to connect each of the upper ends and lower ends of the vertical corner hinge frames; a first panel having side edges thereof inserted between the corresponding vertical corner hinge frames, and top/bottom edges thereof inserted between the corresponding first lower and upper horizontal frames; and a second panel having side edges thereof inserted between the corresponding vertical corner hinge frames and vertical middle hinge frames, and top/bottom edges thereof inserted between the corresponding second upper and lower horizontal frames.
News Article | February 22, 2017
SUNNYVALE, Calif., Feb. 22, 2017 (GLOBE NEWSWIRE) -- Seclore, the leader in Enterprise Rights Management (ERM), today announced the latest release of its flagship data-centric security solution. New capabilities offered provide a more seamless experience for both the sender and recipient. The most impactful update in the new release is the ability to edit protected documents natively in Mac. Seclore for Mac 2.0 packs in powerful new features which make the enterprise even more secure and compliant – while reducing the burden on both IT and end users. The skyrocketing number of enterprise Mac users are now empowered with the same level of data-centric security as their Windows counterparts. “Existing Seclore users that use the iOS platform will now be empowered to do much more than just apply rights and view protected files. They can now open, edit, save, and print protected Office documents in their native Office 2016 apps running on Mac,” stated Abhijit Tannu, CTO at Seclore. “Our goal with this release is to decrease end user friction and increase adoption by enabling users to leverage the entire universe of features provided by Office when working with their protected files on Mac devices.” Additional features in the latest version of Seclore Enterprise Rights Management, include: “Our newest features form an integral part of Seclore’s vision of providing easily adoptable data-centric security solutions to organizations,” said Vishal Gupta, CEO at Seclore. “With a relentless focus on reducing friction at both the sender and receipt stages of the rights management process, Seclore is leading the way in closing the remaining security gaps in organizations’ IT ecosystems.” About Seclore Seclore offers an innovative data-centric security solution, which enables organizations to control usage of files wherever they travel, both within and outside of the organization’s boundaries. The ability to remotely enforce and audit who can view, edit, copy, screen capture and redistribute files empowers organizations to embrace mobility, file-sharing, and external collaboration with confidence. Easy to deploy and use, Seclore extends the security of many DLP, ECM, ERP, EFSS, VDR, CASB, and Mail/Messaging solutions to information that move beyond the perimeter. Seclore was recently recognized by Gartner as a “Cool Vendor” and by Deloitte as one of the “50 Fastest Growing Technology Companies” due to innovations in agentless receipt of protected documents. With more than 10,000 companies across 29 countries, Seclore is helping organizations achieve their data security, governance, and compliance objectives.
News Article | February 15, 2017
Micro Com Systems shares details of scanning archival books and other precious volumes VANCOUVER, BC--(Marketwired - February 14, 2017) - Micro Com Systems, a scanning service in Vancouver, has experience performing a wide variety of conversion tasks. Their longstanding mission has been to assist companies and government agencies in their transition to digital capture and storage of office records. However, many clients have precious books, old volumes of all sizes and descriptions that also require special care. In a new web post, Micro Com Systems explains how they can assist with these jobs. For more, go to: http://www.microcomsys.com/solutions/document-scanning/archival/ Many of the books clients want scanned are priceless in terms of appearance and content. The technicians at Micro Com Systems scoured the marketplace, looking for the best device that could reliably capture information without potentially harming these precious antiques. Eventually, they decided on the Atiz Bookdrive Pro. The simple but ingenious design of the Bookdrive Pro allows it to capture both sides of a book right to the gutter or margin at very high resolution. It captures full color images and records it in a RAW format. During subsequent processing, team technicians will perform image cleanup, color manipulation, cropping and conversion to any image format. The result is a true-to-format document that can be read and shared, without compromising the original. To learn more about document scanning and digitization services offered by Micro Com Systems Vancouver, please contact (604) 872-6771. Since 1975, Micro Com Systems has been providing local businesses with Document Management Solutions. Their list of products and services includes: Document Imaging & Management, Archival & Book Scanning, Medical Imaging, OCR, Large Format Scanning, Microfilm Scanning, Aperture Card Scanning, Enterprise Report Management (ERM), High Speed Printing, Capture Software, and Capture Equipment. For more information, please visit http://www.microcomsys.com/ or call (604) 872-6771.