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Commitments and Contingencies | 12 Months Ended
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Dec. 31, 2016
Commitments and Contingencies [Abstract] |
COMMITMENTS AND CONTINGENCIES | 28. COMMITMENTS AND CONTINGENCIES A. Commitments As at December 31, 2016, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following:
millions of Canadian dollars |  | 2017 |  | 2018 |  | 2019 |  | 2020 |  | 2021 | Thereafter |  | Total
Purchased power (1) | $ | 253 | $ | 224 | $ | 206 | $ | 202 |  | 198 | $ | 2,272 | $ | 3,355
Fuel and gas supply |  | 475 |  | 161 |  | 109 |  | 28 |  | 22 |  | - |  | 795
Demand Side Management |  | 42 |  | 48 |  | 13 |  | - |  | - |  | - |  | 103
Transportation (2) |  | 496 |  | 392 |  | 310 |  | 280 |  | 196 |  | 1,622 |  | 3,296
Long-term service agreements (3) |  | 92 |  | 55 |  | 67 |  | 44 |  | 42 |  | 227 |  | 527
Capital projects |  | 133 |  | - |  | - |  | - |  | - |  | - |  | 133
Equity investment commitments (4) |  | 236 |  | - |  | - |  | 200 |  | - |  | - |  | 436
Leases and other (5) |  | 66 |  | 17 |  | 14 |  | 12 |  | 8 |  | 70 |  | 187
| $ | 1,793 | $ | 897 | $ | 719 | $ | 766 | $ | 466 | $ | 4,191 | $ | 8,832
(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.
(4) Emera has a commitment in connection with the Federal Loan Guarantee ("FLG") to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.
(5) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.
In connection with the acquisition of TECO Energy, Emera made certain commitments approved by the NMPRC. See note 4 for additional information. Beginning in 2018, NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over 35 years. The timing and amount of future payments could change based on UARB approval and final costing of the Maritime Link after construction is complete. B. Legal Proceedings Emera Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed 12 separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acqui sition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints sought to enjoin the merger pursuant to the acquisition agreement. On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Direct ors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of unders tanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger, which have now been made. On December 16, 2016, the judge entered a n order and final judgement approving a stipulation of settlement negotiated by the parties, thereby concluding this matter. Emera Florida and New Mexico TECO Coal TECO Coal was sold by TECO Energy on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”), prior to Emera’s acquisition. On March 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified. The claim asserted breach of certain representations, and fraud and willful misconduct in connection therewith, of the Secur ities Purchase Agreement dated September 21, 2015 by and between TECO Diversified and Cambrian related to the purchase of TECO Coal by Cambrian. While the outcome of such matter is uncertain, management does not believe that its ultimate resolution will h ave a material adverse effect on the Company’s results of operations, financial condition or cash flows. TECO Guatemala Holdings (“TGH”) On December 19, 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the Dominican Republic Central America – United States Fee Trade Agreement, issued an award in the case (“the Award”). The ICSID Tr ibunal unanimously found in favor of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus 2 per cent. On April 18, 2014, Guatemala filed an application for annulm ent of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. On April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain defici encies in the ICSID Tribunal’s determination of the amount of TGH’s damages. On April 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21 million USD award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to t he annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding. On September 23, 2016, TGH filed a request for resubmission to arbitration. On October 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission. TGH and Guatemala have each selected an arbitrator and ICSID has recently selected a President for the new tribunal. Results to date do not reflect any benefit. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and Peopl es Gas divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31, 2016, TEC has estimated its ultimate financial liability to be $43 million ($32 million USD), primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not disco unted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigat ion which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. The FPSC has approved, as part of the PGS depreciation settlement as discussed in note 17, an agreement to accelerate the amortization of the regulated asset associated w ith this reserve. Emera Maine On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the FERC alleging that the 11.14 per cent base RO E under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint that changed the methodology used to set the ROE and resulted in a lower base transmission ROE of 10.57 per cent and a lower total ROE (inclusive of incentive adders) of 11.74 per cent for the period of October 1, 2011 to December 31, 2012. The ROE was confirmed by FERC in two subsequent orders and has now been appealed to the U.S. Court of Appeals for the DC Circuit. The Court has decided to hold the appeal of this case in abeyance pending the outcome of the ENE Case and MA AG II Case discussed below. On June 30, 2016, Emera Maine completed the processing of refunds to customers to reflect the 10.57 per cent ROE. On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the 11.14 per cent base ROE under the OATT was un just and unreasonable (“the ENE Case”). This complaint applies to the period from January 1, 2013 to March 31, 2014. On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC on similar gro unds (“the MA AG II Case”) in relation to the period from July 31, 2014 to October 31, 2015. The ENE Case and MA AG II Case were subsequently consolidated by FERC into a single case. On March 22, 2016, a FERC Administrative Law Judge (“ALJ”) issued a reco mmended decision to FERC with respect to the consolidated cases. The recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum ROE, and the recommendation for the MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. The ALJ’s recommended decision is not definitive and FERC has the ability to adjust the ALJ’s recommended decision. A decision by FERC is not expected until early 2017. On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base ROE to 8.61 per cent and the maximum ROE to 11.24 per cent for the period April 29, 2016 to July 29, 2017. Emera Maine has recorded a reserve of $5 million pre-tax ($4 million USD) (December 31, 2015 - $7 million or $5 million USD) for the ENE Case and MA AG II Case. The reserves r ecorded for these complaints have been recorded as “Regulatory Liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements of Income. The reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve h as been made as a result of the EMCOS complaint, as the outcome is considered uncertain. Other Legal Proceedings Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. C. Environment Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon presen t environmental laws and regulations. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 28A. The estimated expenditures do not include costs related to possible changes in the environmental laws o r regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions. Emera Florida and New Mexico Tampa Electric operates fossil fuel burning power plants with air emissions regulated by the Clean Air Act and material Clean Water Act implications and impacts by federal and state legislative initiatives. Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of Clean Air Interstate Rule (“CAIR”) and th ese expenses were rate recoverable under the Florida environmental cost recovery clause (“ECRC”) as approved by the FPSC. Similarly, future expenses should be eligible for recovery upon petition by Tampa Electric and approval by the FPSC. On July 7, 2011, EPA released its final CAIR-replacement rule, called Cross-State Air Pollution Rule (“CSAPR”). An update to CSAPR was finalized on October 26, 2016 and will be implemented in 2017. Based on updated EPA modeling and favorable consideration of atmospheri c dynamics, Florida is no longer subject to CSAPR requirements. However, Florida (including Tampa Electric power plants) could be subject to a future version of CSAPR as a result of an expected update triggered by compliance with the more stringent 2015 o zone standard or ongoing litigation related to current rule applicability. NSPI NSPI’s activities are subject to a broad range of federal, provincial, regional and local laws and environmental regulations, designed to protect, restore and enhance the qua lity of the environment including air, water and solid waste. In November 2014, the Government of Canada and the Province of Nova Scotia entered into a Greenhouse gas (“GHG”) emission regulatio ns equivalency agreement, which allows NSPI to achieve compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory requirements as they are deemed to be equivalent. In March 2016, Canada’s First Ministers issued the “Vancouver Declaration” on clean growth and climate change. First Ministers agreed to develop a Pan-Canadian Framework and implement it by early 2017. Four working groups, comprised of federal, provincial and territorial officials were established to prov ide recommendations and research to the Federal government. NSPI provided input into this process through the Nova Scotia government, the Government of Canada and directly to the working groups through the submission of a discussion paper. In October 2 016, the Government of Canada announced that the pan-Canadian framework would include a national price on carbon component, implemented by 2018 through either a carbon tax or a cap and trade system, applicable in each province except those which enact thei r own comparable carbon pricing mechanism by that time. On November 21, 2016, the Government of Canada announced a second component of the plan would include an accelerated plan to phase out coal in Canada, to transition Canada's electricity system towar ds 90 per cent non-emitting generation sources by 2030. On the same day, the Province of Nova Scotia and the Government of Canada made two announcements regarding Nova Scotia’s participation in the Pan-Canadian plan: Carbon pricing component An agreemen t in principle covering the carbon component had been reached and will be governed on the following principles: Nova Scotia will adopt a province-wide 2030 emissions reduction target equal or greater than Canada’s target of a 30 per cent reduction from 20 05 levels by 2030; Nova Scotia will implement an agreed upon cap and trade system; and The Province of Nova Scotia and the Government of Canada will agree upon a methodology and scenarios for the modeling of projected GHG emissions to support the developme nt of Nova Scotia’s cap and trade system. Accelerated phase out of coal component Nova Scotia and the Government of Canada will establish a new equivalency agreement that will enable the province to move directly from fossil fue ls to clean energy sources and enable NSPI’s coal-fired plants to operate at some capacity beyond 2030. On December 9, 2016, the Government of Canada and eight provinces (including Nova Scotia) signed the Pan Canadian Framework on Clean Growth and Climate Change. The Government of Canada has committed to ensuring that the provinces and territories have the flexibility to design their own policies and programs to meet emission-reduction targets, supported by federal investments in infrastructure, spe cific emission-reduction opportunities and clean technologies. Details under the agreements are expected to be finalized by the end of 2017. NSPI anticipates that any costs prudently incurred to achieve the legislated reductions would be recoverable from customers under NSPI’s regulatory framework. NSPI will continue to work with both the Province of Nova Scotia and the Government of Canada as the details of the agreements are finalized and to advance solutions that are in the best interest of customers. The Government of Canada has indicated their intention to resume discussions regarding Base Level Industrial Emission Requirements (”BLIER”s) for sulphur dioxide and nitrogen dioxide and have outlined their intention to develop a Clean Energy Standard for natural gas and possibly diesel. The details of both processes are not yet known. NSPI will participate in these processes in 2017. NSPI estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulatio ns will be approximately $41 million during fiscal 2017 and are estimated to be $41 million from 2018 through 2021. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 28A. Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2016. Polychlorin ated Biphenyl Equipment In response to the Canadian Environmental Protection Act 1999, 2008 Polychlorinated Biphenyl (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that fall under the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole mounted transformers. The combined total cost of these projects is estimated to be $43 million and, as at December 31, 2016, approximately $28 million (December 31, 2015 – $20 million) has been spent to date. NSPI h as recognized an ARO on the balance sheet of $11 million as at December 31, 2016 (December 31, 2015 – $15 million) associated with the PCB phase-out program. Emera Energy Emissions The NEGG Facilities are subject to the RGGI for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. The NEGG Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impa ct financial and operational performance. D. Principal Risks and Uncertainties In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net assets or liquidity or capital resources in the near term. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future. Sound risk management is an essenti al discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management. Regulatory and Political Risk The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. As cost-of-service utilities with an obligation to serve customers, Tampa Electric, PGS, NMGC, NSPI, Emera Maine, BLPC, GBPC, and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon approval by the respect ive regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate c an be impacted by significant shifts in government policy (including shifts in policy which could occur as a result of climate change concerns) and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, LIL, M&NP and Lucelec. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate regulated companies and their respective regulators determin e whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory ap proach through technical conferences and, where appropriate, negotiated settlements. Weather and Climate Risk Shifts in weather patterns affect energy sales and associated revenues and costs. Extreme weather events generally result in increased operatin g costs associated with restoring service to customers as a result of unplanned outages. Emera responds to outages which occur as a result of significant weather events according to each subsidiary’s respective emergency services restoration plan. Changes in Environmental Legislation Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting GHG emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials. In addition to imposing continuing compliance obligations, there are permit re quirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera. In addition, Emera’s business could be materially affected by changes in government poli cy, utility regulation, and environmental and other legislation that could occur in response to environmental and climate change concerns. New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to ad ditional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments. Emera manages its environmental risk by operating in a manner that is respectful and protective of the environm ent and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating su bsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates globally, with an in creasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results. Co nsistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses short-term foreign currency derivative instruments to hedge specific transactions. The Company en ters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and capital projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange. The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes, or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries are included in AOCI. Capital Market and Liquidity Risk Emera’s operations and projects in development require significant capital investments in property, plant and equipment. Consequently, Emera is an active participant in the debt and equity markets. After giving effect to the TECO Energy acquisition, Emera now has total debt of $15 billion. Any disruption in capital markets could have a material impact on Emer a’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events throughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the company’s business a nd regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A change to a credit rating as a result of changes in any of these items could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated ca sh flows, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs. Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturi ties. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. For Emera’s regulated subsidiaries, the cost of debt is a component of rat es and prudently incurred debt costs are recovered from customers. While regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasi ng interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives. Commercial Relationships Risk The Company is exposed to commercial relationships risk in respect of its reliance on certain key partners, suppliers and customers. The Company manages its commercial relationships risk by monitoring credit risk and monitoring of significant devel opments with its customers, partners and suppliers. Commodity Price Risk A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs. Income Tax Risk The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax benefits are determined by existing tax laws and could be negatively impacted by changes in laws. “Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in the corporate income t ax rate. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would also reduce the value of the Company’s existing deferred tax assets and could result in a charge to earnings if written down. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results. E. Guarantees and Letters of Credit Emera had significant guarantees and letters of credit on behalf of third parties outstanding as discussed below. These are not included within the Consolidated Balance Sheets as at December 31, 2016. Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain conditions set out in that guarantee. The cost of those obligations is estimated to be $1.577 billion, which reduces in the ord inary course as project costs are paid. The current exposure as at December 31, 2016 is $577 million. TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities. Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate coll ateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. As a result of the sale i n September 2015, the letters of indemnity guaranteed $124 million ($95 million USD). TECO Energy has remaining letters of indemnity related to TECO Coal, which totaled $80 million ($59 million USD) at December 31, 2016. As of that date Cambrian had posted ap proximately $54 million ($40 million USD) of additional reclamation bonds to replace corresponding reclamation bonds supported by TECO Energy’s indemnity. TECO Energy’s indemnity obligations in respect of such bonds will not be released until the applicab le State department processes the applicable permit transfers and releases such bonds. These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts outlined above represent the ma ximum theoretical amounts that TECO Energy would be required to pay to the surety companies. The company is working with Cambrian on the process to replace the remaining bonds. Pursuant to the securities purchase agreement, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained. NSPI has a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2017 and is renewed annually. The amount committed as at December 31, 2016 was $47 million. Emera has standby letters of credit in the amount of $24 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one-year term and a re renewed annually as required. Collaborative Arrangement s For the years ended December 31, 2016 and 2015, the Company has identified the following material collaborative arrangements: Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portio n of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in operating, maintenance and general (“OM&G”) expenses. In 2016, NSPI recognized $18 million net expense (2015 - $10 million) in “Regulated fuel for generation and purchased power” and $5 million (2015 - $2 million) in “OM&G”.

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