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Commitments and Contingencies | 12 Months Ended
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Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract] |
Commitments and Contingencies | 26. COMMITMENTS AND CONTINGENCIES A.Commitments As at December 31, 2019, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
millions of Canadian dollars |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 | Thereafter |  | Total
Purchased power (1)(2) | $ | 210 | $ | 233 | $ | 237 | $ | 246 | $ | 249 | $ | 2,228 | $ | 3,403
Transportation (3) |  | 514 |  | 398 |  | 340 |  | 281 |  | 264 |  | 2,720 |  | 4,517
Capital projects (4) |  | 411 |  | 109 |  | 103 |  | 86 |  | - |  | - |  | 709
Fuel, gas supply and storage |  | 466 |  | 133 |  | 22 |  | 1 |  | - |  | - |  | 622
Long-term service agreements (5)(6) |  | 52 |  | 37 |  | 36 |  | 27 |  | 26 |  | 100 |  | 278
Equity investment commitments (7) |  | 240 |  | - |  | - |  | - |  | - |  | - |  | 240
Leases and other (8) |  | 19 |  | 19 |  | 18 |  | 17 |  | 8 |  | 118 |  | 199
Demand side management |  | 38 |  | 41 |  | 43 |  | - |  | - |  | - |  | 122
| $ | 1,950 | $ | 970 | $ | 799 | $ | 658 | $ | 547 | $ | 5,166 | $ | 10,090
As noted below, contractual obligations at December 31, 2019 include amounts related to Emera Maine. On completion of the sale of Emera Maine, all of the remaining future contractual obligations will be transferred to the buyer. Refer to note 4 for additional information.
(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(2) Includes $520 million related to Emera Maine ($13 million in 2020; $23 million in 2021; $27 million in 2022; $31 million in 2023; $31 million in 2024 and $395 million thereafter).
(3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(4) Includes $345 million of commitments related to Tampa Electric's solar and Big Bend Power Station modernization projects.
(5) 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.
(6) Includes $44 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($19 million in 2020; $9 million in 2021; $8 million in 2022; and $8 million in 2023).
(7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.
(8) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.
NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2019 was $111 million subject to a $10 million holdback and as at December 31, 2019, $101 million has been paid. The UARB approved payment for 2020 is $145 million, subject to a holdback of up to $10 million. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and estimated amounts of $164 million and $162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 3 7-year commitment period are dependent on regulatory filings with the UARB. Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland or Nova Sco tia. This energy would be transmitted from Nova Scotia to New England energy markets beginning at first commercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table. B.Legal Proceedings TECO Guatemala Holdings (“TGH”) In 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 Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 mill ion USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the 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 wel l 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. A new tribunal was constituted, and th e matter was fully briefed. A hearing was held in March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. On October 1, 2019, the court granted TGH’s motion for summary judgment which will allow TGH to seek collection of the award plus interest when the order is final. Guatemala has appealed that decision. Results to date do not reflect any benefit. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS 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, 2019, TEC has estimated its financial liability to be $2 7 million ($21 million USD), pr imarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. 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. Th e 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 experienc e with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs ar e involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy 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. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities the mselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings. Emera Maine From 2011 to 2016, four separate complain ts were filed with the FERC to challenge the base return on equity (“ROE”) under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”). Complaint I, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, was remanded to the FERC by the US Court of Appeals in 2017 for further proceedings. No reserve has been made with respect to Complaint I due to uncertainty of the outcome. Complaints II and III (the “ENE” and “MA AG II” cases), brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively, have been joined together and are presently pending before the FERC. Emera Maine has recorded a reserve of approximately $4 million USD for these cases. These reserves have been recorded as “Regulatory liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Stateme nts of Income. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome. Complaint IV was filed by the Eastern Massachusetts Consumer Owned Systems (“EMCOS”). On March 27, 2018, a FERC Administrative Law Judge issued an Ini tial Decision concluding that the currently filed base ROE of 10.57 per cent, which with incentive adders may reach a maximum ROE of 11.74 per cent, is not unjust and unreasonable. This decision was appealed to the FERC. No reserve has been made in relatio n to Complaint IV due to the uncertainty of the final outcome. On October 16, 2018, the FERC issued an order that addressed all four complaint proceedings. The FERC order proposed a new methodology to set ROEs. Based on the new methodology, the FERC’s pr eliminary finding was a 10.41 per cent base ROE for the ISO-NE OATT. The FERC has permitted parties to comment on the new methodology and its application to the four pending complaint proceedings. No new or additional reserves have been made with respect t o any of the four pending complaints due to uncertainty. On Nov ember 21, 2019, the FERC approved an order affecting transmission ROEs in the Midcontinent ISO region (MISO) that alters the Commission’s methodology for analyzing the base return on equity component of a jurisdictional public utility’s rates. T he methodology applied in the M ISO case may be applied by the FERC in the pending ISO NE cases. No date for a decision has been made yet, but the FERC is expected to rule on these three outstanding ISO-NE cases in 2020. Additionally, both the MISO case, and a decision in the ISO-NE case s, will be subject to further appeal rights and, if appealed, a final decision would be unlikely to occur before Q4 2020. Therefore, no change in Emera Maine’s accrual related to ROE complaints has been made as a result of the MISO decision. 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. Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated wit h derivative instruments and fair value measurements are discussed in note 13 and note 14. Sound risk management is an essential 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. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates internati onally, with an increasing 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 affe ct results. Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and ea rnings exposure. The Company may enter into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams and capital expenditures, and on net income earned outside of Canada. 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 speculativ e purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI. Liquidity and Capital Market Risk 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 cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, accept able pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs. Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions a nd ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant c apital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access cost-effective capital could have a material impact on Emera’s abil ity to fund its growth plan. 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 and regulatory framew ork, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other sever weather events. A decrease in a cred it rating 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 operati ons. Emera manages this risk by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation, preferred share units and deferred share units. Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt financ ing 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 maturities. 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 rates and prudently incurred debt costs are recovered from customers. 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 rise in times of increasing 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. Commodity Price Risk A large portion of the Compa ny’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 br oader 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 subsidia ries 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 assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status o f existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results. D.Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2019: TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The g uarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which is expected to terminate on Janu ary 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD. The Company has standby letters of credit and surety bonds in the amount of $82 million USD (December 31, 2018 - $67 milli on USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds t ypically have a one-year term and are renewed annually as required. Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The letter of credit expires in June 2020 and is renewed annuall y. The amount committed as at December 31, 2019 was $52 million (December 31, 2018 - $49 million). Collaborative Arrangement s For the years ended December 31, 2019 and 2018, 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 portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in OM&G expenses. In 2019, NSPI recognized $19 million net expense (2018 - $1 9 million) in “Regulated fuel for generation and purchased power” and $3 million (2018 - $2 million) in OM&G.

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