Exhibit 99.3

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included as Exhibit 99.2 of this Current Report on Form 8-K. This report includes certain forward-looking statements. Forward-looking statements are identified by words and phrases such as: “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast,” “should,” “predict,” “could,” “will,” “may,” and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management’s beliefs and assumptions and on currently available information and include, but are not limited to, statements regarding anticipated financial performance, future capital expenditures, liquidity, market or competitive conditions, regulations, organic or strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings and cash distributions to unitholders. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

Management’s Discussion and Analysis is intended to give our unitholders an opportunity to view the Partnership through the eyes of our management. We have done so by providing management’s current assessment of, and outlook of the business of the Partnership. Our discussion and analysis includes the following:

· BASIS OF PRESENTATION;

· EXECUTIVE OVERVIEW;

· HOW WE EVALUATE OUR OPERATIONS;

· RESULTS OF OPERATIONS;

· LIQUIDITY AND CAPITAL RESOURCES;

· CRITICAL ACCOUNTING ESTIMATES;

· CONTINGENCIES; and

· RELATED PARTY TRANSACTIONS.

BASIS OF PRESENTATION

See the Basis of Presentation section of Note 2- Significant Accounting Policies, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K, for important information on the content and comparability of our historical financial statements.

The initial acquisition of a 49.9 percent interest in PNGTS on January 1, 2016 and additional 11.81 percent on June 1, 2017 (collectively, the PNGTS Acquisitions) were accounted for as transaction between entities under common control, which are required to be accounted for as if the PNGTS Acquisitions had occurred at the beginning of the year, with financial statements for prior periods recast to furnish comparative information. Accordingly, the accompanying financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all periods presented.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent in Iroquois (Refer to Note 24-Subsequent Events Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K). This transaction was accounted prospectively and did not form part of the accompanying financial information.

EXECUTIVE OVERVIEW

Net income (loss) attributable to controlling interests was $248 million or $3.21 per common unit in 2016 compared to $37 million, or $(0.03) per common unit in 2015. Adjusted earnings, which excluded the impact of the $199 million non-cash impairment charge on our investment in Great Lakes in the fourth quarter 2015, increased by $12 million in 2016 compared to 2015. Cash distributions declared per common unit increased by six percent from $3.51 per common unit in 2015 to $3.71 per common unit in 2016. Please see “Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit” for more information.

Our 2016 EBITDA increased by $210 million to $433 million compared to $223 million in 2015 primarily due to the recognition of $199 million non-cash impairment charge to our investment in Great Lakes in 2015. Our Adjusted

EBITDA, which excluded the impact of the $199 million non-cash impairment charge on our investment in Great Lakes, increased by three percent to $433 million and Distributable cash flow increased by eight percent to $313 million. Please see “Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit” for more information.

2017 Developments

Great Lakes - Great Lakes is required to file a new Section 4 rate case with rates effective no later than January 1, 2018 as part of the settlement agreement with customers approved in November 2013. On March 31, 2017, Great Lakes filed its rate case pursuant to Section 4 of the Natural Gas Act. The rates proposed in the filing will become effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. Great Lakes is currently seeking to achieve a mutually beneficial resolution through settlement with its customers.

On April 24, 2017, Great Lakes reached an agreement on the terms of a potential new long-term transportation capacity contract with its affiliate, TransCanada. The contract is for a term of 10 years with a total contract value of up to $758 million. The contract may commence as soon as November 1, 2017 and contains termination options beginning in year three. The contract is subject to the satisfaction of certain conditions, including but not limited to approval by the Canadian National Energy Board of an associated contract between TransCanada and third party customers. Great Lakes current rate structure includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above a calculated return on equity threshold. Additionally, Great Lakes is currently pursuing resolution of its March 31, 2017 General Section 4 Rate Filing. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

Debt Offering-On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017 acquisitions. The indenture for the notes contains customary investment grade covenants.

2017 Acquisition — On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1) (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

The Iroquois pipeline transports natural gas under long-term contracts and extends from the TransCanada Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut. Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Both the Iroquois and PNGTS pipelines are critical natural gas infrastructure systems in the Northeast U.S. market and the addition of Iroquois to the Partnership’s asset portfolio will further diversify our cash flow.

Northern Border — Northern Border revenues are now substantially supported by firm transportation contracts through March 2020. The continued successful renewals of these contracts provide a strong indication of Northern Border’s attractiveness to its customers.

2016 Developments

2016 PNGTS Acquisition- On January 1, 2016, the Partnership completed the $228 million acquisition of a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The purchase price was comprised of $193 million in cash and the assumption of $35 million in proportional PNGTS debt. This transaction added a new market geography for us, extending our breadth of operations and further diversifying our cash flow stream.

Tuscarora Rate Case - On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services were just and reasonable. On September 22, 2016, FERC approved the settlement (Tuscarora Settlement) Tuscarora made with its customers that resolved the Section 5 review initiated by FERC. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate

case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease by an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022. While this new rate structure reduced Tuscarora’s cash flows beginning August 1, 2016, the achievement of rate certainty helps ensure predictable cash flows from this pipeline system.

Outlook of Our Business

TransCanada, the ultimate parent company of our General Partner, closed the acquisition of all of the outstanding publicly-held common units of Columbia Pipeline Partners LP on February 17, 2017. This acquisition leaves TransCanada with a single MLP in TC PipeLines, which it describes as a core element of TransCanada’s strategy.

TransCanada is advancing CAD $24 billion of near-term capital projects, approximately CAD $9 billion of which has been invested to date with the remainder to be spent largely over the next three years. TransCanada says it intends to prudently fund its capital program in a manner that is consistent with maintaining its financial strength, including potential drop downs to the Partnership.

The Partnership’s financial performance continues to benefit from its transactions with TransCanada, Despite the volatility in energy commodity prices, our portfolio of eight FERC-regulated interstate natural gas pipelines is expected to deliver generally stable results in 2017 due to ship-or-pay contracts with creditworthy customers.

HOW WE EVALUATE OUR OPERATIONS

We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP because we believe they enhance the understanding of our operating performance. We use the following non-GAAP measures:

EBITDA

We use EBITDA as an approximate measure of our operating cash flow and current operating profitability. It measures our earnings from our pipeline systems before certain expenses are deducted.

Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit

We have evaluated our financial performance and position inclusive of the impairment charge to our investment in Great Lakes recognized during the fourth quarter of 2015, however, we believe it is not reflective of our underlying operations during the periods presented. Therefore, we have presented adjusted EBITDA, adjusted earnings and adjusted earnings per common unit as non-GAAP measures that exclude the impact of the $199 million non-cash impairment charge.

Distributable Cash Flows

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period.

Please see “Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

Our equity interests in Northern Border, Great Lakes, 61.71 percent ownership in PNGTS, and our full ownership of GTN, Bison, North Baja and Tuscarora were our only material sources of income during the periods presented. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

(unaudited) (millions of dollars, except per common unit amounts)	2016 (a)		2015 (a)		$ Change (d)		% Change (d)

Transmission revenues	426		417		9		2
Equity earnings	97		97		—		—
Impairment of equity-method investment	—		(199	)	199		100
Operating, maintenance and administrative	(92	)	(97	)	5		5
Depreciation	(96	)	(95	)	(1	)	(1	)
Financial charges and other	(71	)	(63	)	(8	)	(13	)
Net income before taxes	264		60		204		*

Income taxes	(1	)	(2	)	1		50
Net Income	263		58		205		*

Net income attributable to non-controlling interests	15		21		6		29
Net income attributable to controlling interests	248		37		211		*

Adjusted earnings (b)	248		236		12		5

Net income (loss) per common unit (c)	3.21		(0.03	)	3.24		*

Adjusted earnings per common unit (b)	3.21		3.03		0.18		6

(a) Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b) Adjusted earnings and Adjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided for below.

(d) Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.

* Change is greater than 100 percent.

Net income attributable to controlling interests increased by $211 million to $248 million in 2016 compared to $37 million in 2015, resulting in net income per common unit during the year of $3.21 after allocations to the General Partner and to the Class B units. This increase was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015 which lowered our net income attributable to controlling interests in 2015. (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

The Partnership’s Adjusted earnings were higher by $12 million in 2016 compared to 2015, an increase of $0.18 per common unit mainly due to the following:

Transmission revenues - increase of $9 million primarily due to the net effect of:

· higher discretionary revenues on GTN from short-term services sold to its customers;

· lower discretionary revenues on PNGTS from short-term services sold to its customers;

· full year of revenues from GTN’s Carty lateral system which was placed into service in October 2015; and

· lower transportation rates on GTN as a result of the settlement reached with its customers effective July 1, 2015.

Operating, maintenance and administrative - generally lower expenses in 2016 as a result of lower operational costs on our consolidated entities. Additionally, dropdown costs were incurred in 2015 related to the acquisition of the initial 49.9 percent interest on PNGTS.

Financial charges and other - $8 million increase primarily due to the net effect of:

· additional borrowings to fund a portion of our recent acquisitions

· lower interest incurred by PNGTS as a result of its 2016 principal payments on its long term debt

· no interest was incurred in 2016 on PNGTS’ rate refund liability due to the payment of all of PNGTS’ outstanding rate refund liability on April 15, 2015. (See Note 2-Significant Accounting Policies-Revenue Recognition section, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more details)

Net income attributable to non-controlling interests - $6 million decrease primarily due to the Partnership’s 100 percent ownership in GTN effective April 1, 2015.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

(unaudited) (millions of dollars, except per common unit amounts)	2015 (a)		2014 (a)		$ Change (d)		% Change (d)

Transmission revenues	417		410		7		2
Equity earnings	97		88		9		10
Impairment of equity-method investment	(199	)	—		(199	)	(100	)
Operating, maintenance and administrative	(97	)	(98	)	1		1
Depreciation	(95	)	(96	)	1		1
Financial charges and other	(63	)	(61	)	(2	)	(3	)
Net income before taxes	60		243		183		(75	)

Income taxes	(2	)	(2	)	—		—
Net Income	58		241		183		(76	)

Net income attributable to non-controlling interests	21		46		25		54
Net income attributable to controlling interests	37		195		158		(81	)

Adjusted earnings (b)	236		195		41		21

Net income (loss) per common unit (c)	(0.03	)	2.67		2.70		*

Adjusted earnings per common unit (b)	3.03		2.67		0.36		13

(a) Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b) Adjusted earnings and Adjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided for below.

(d) Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.

* Change is greater than 100 percent.

Net income attributable to controlling interests decreased by $158 million to $37 million in 2015 compared to $195 million in 2014, resulting in a net loss per common unit during the year of $0.03 after allocations to the General Partner and to the Class B units. This decrease was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015. (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

The Partnership’s Adjusted earnings were higher by $41 million in 2015 compared to 2014, an increase of $0.36 per common unit due to the following:

Transmission revenues - increase of $7 million primarily due to higher discretionary revenues on GTN from short-term services sold to its customers.

Earnings from equity investments - $9 million increase mainly due the net effect of:

· lower equity earnings from Northern Border primarily due to lower revenues from the sale of short-term services as a result of the milder winter in 2015 compared to 2014; and

· higher equity earnings from Great Lakes in 2015 primarily due to additional revenues from new contracts with ANR, a related party.

Operating, maintenance and administrative - $1 million decrease was mainly due to the net effect of: lower expenses on Bison related to pipeline integrity program spending;

· lower property taxes on Bison as compared to 2014;and

· higher operating costs on PNGTS

Financial charges and other - $2 million increase mainly due to the net effect of:

· additional borrowings to fund a portion of our recent acquisitions;

· lower interest incurred by PNGTS as a result of its 2015 principal payments on its long term debt; and

· lower interest on PNGTS’ rate refund liability due to the payment of all of PNGTS’ outstanding rate refund liability on April 15, 2015. (See Note 2-Significant Accounting Policies-Revenue Recognition, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more details)

Net income attributable to non-controlling interests - $25 million decrease due to our 100 percent ownership in GTN and Bison effective April 1, 2015 and October 1, 2014, respectively.

Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit

Reconciliation of Net income attributable to controlling interests to Adjusted earnings

(millions of dollars)
Year ended December 31	2016	2015	2014
Net income attributable to controlling interests	248	37	195
Add: Impairment of equity-method investment	—	199	—
Adjusted earnings	248	236	195

Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit

Year ended December 31	2016	2015		2014
Net income (loss) per common unit-basic and diluted (a)	3.21	(.03	)	2.67
Add: per unit impact of impairment of equity-method investment (b)	—	3.06		—
Adjusted earnings per common unit	3.21	3.03		2.67

(a) Net income (loss) per common unit prior to recast.See also Note 12, Notes to Consolidated Financial statements for the year ended December 31, 2016 included in exhibit 99.2 of this Current Report on Form 8-K for details of the calculation of net income (loss) per common unit- basic and diluted.

(b) Computed by dividing the $199 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its effective two percent interest, by the weighted average number of common units outstanding during the period.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our principal sources of liquidity and cash flows include distributions received from our equity investments, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TransCanada through our General Partner and as holder of all our Class B units) primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity. Overall, we believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with a history of consistent cash flow from operating activities, provide a solid foundation to meet future liquidity and capital

requirements. We expect to be able to fund our liquidity and capital resource requirements, including our distributions and required debt repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility. The following table sets forth the available borrowing capacity under the Partnership’s Senior Credit Facility.

(unaudited) (millions of dollars)	June 30, 2017	December 31, 2016	December 31, 2015

Total capacity under the Senior Credit Facility	500	500	500
Less: Outstanding borrowings under the Senior Credit Facility	170	160	200
Available capacity under the Senior Credit Facility	330	340	300

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow. However, since the fourth quarter of 2010, Great Lakes has funded its debt repayments with cash calls to its owners.

Capital expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ owners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although limited by FERC, allow them to request credit support as circumstances dictate.

Summarized Cash Flow

Year Ended December 31,
(millions of dollars)	2016 (a)		2015(a)		2014(a)

Net cash provided by (used in):
Operating activities	417		260		417
Investing activities	(230	)	(326	)	(261	)
Financing activities	(178	)	(32	)	(119	)
Net increase in cash and cash equivalents	9		(98	)	37
Cash and cash equivalents at beginning of the period	55		153		116
Cash and cash equivalents at end of the period	64		55		153

(a) Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

Cash Flow Analysis for the Year Ended December 31, 2016 compared to Same Period in 2015

Operating Cash Flows

Net cash provided by operating activities increased by $157 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:

· higher earnings as discussed in more detail in the “Results of Operations” section.

· higher distributed earnings received from equity investments in 2016 as a result of additional revenues from new contracts with ANR, a related party

· payment of all of PNGTS’ outstanding rate refund liability in 2015, including interest as a result of its rate case settlement approved by FERC on February 2015. Total refunds accumulated to $114 million, including $8 million of interest, and were paid to customers on April 15, 2015. (See Note 2-Significant Accounting Policies-Revenue Recognition, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more details); and

· timing of working capital changes. The majority of the timing impact relates to the settlement of our accounts payable and accrued liabilities.

Investing Cash Flows

Net cash used in investing activities decreased by $96 million in the twelve months ended December 31, 2016 compared to the same period in 2015 as we invested a lesser amount on our initial 49.9 percent acquisition of interest on PNGTS compared to our investment during the same period in 2015. In 2015, we paid $264 million to acquire the remaining 30 percent interest in GTN compared to $193 million paid for the acquisition of a 49.9 percent interest in PNGTS in 2016. Additionally, we had higher capital expenditures in 2015 due to expenditures related to the construction of the Carty Lateral.

Financing Cash Flows

Net cash used in financing activities increased by $146 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:

· $254 million decrease in net issuances of debt in 2016 as compared with 2015;

· $123 million increase in our ATM equity issuances in 2016 as compared with 2015;

· $22 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs;

· $12 million of distributions paid to Class B units in 2016;

· $9 million decrease in distributions paid to non-controlling interest due to the Partnership’s 100 percent ownership in GTN effective April 1, 2015; and

· $10 million decrease in distributions paid to TransCanada as the former parent of PNGTS due to the Partnership’s acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016.

Cash Flow Analysis for the Year Ended December 31, 2015 compared to Same Period in 2014

Operating Cash Flows

Net cash provided by operating activities decreased by $157 million in the twelve months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

· higher adjusted earnings as discussed in more detail in the “Results of Operations” section; and

· timing of working capital changes. The majority of the timing impact relates to the settlement of our accounts payable and accrued liabilities.

Investing Cash Flows

Net cash used in investing activities increased by $65 million in the twelve months ended December 31, 2015 compared to the same period in 2014 as we invested a higher amount on the acquisition of the remaining 30 percent interest in GTN effective April 1, 2015 compared to our investment in the acquisition of the remaining 30 percent interest in Bison. In 2015, we paid $264 million to acquire the remaining 30 percent interest in GTN compared to $217 million the remaining 30 percent interest in Bison. Additionally, we had higher capital expenditures in 2015 due to expenditures related to the construction of the Carty Lateral. We also paid an additional $25 million to TransCanada in 2014 related to our 2013 Acquisition as a result of the attainment of certain events with respect to the Carty Lateral project.

Financing Cash Flows

Net cash used in financing activities decreased by $87 million in the twelve months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

· $97 million increase in net issuances of debt in 2015 as compared with 2014;

· $29 million decrease in our ATM equity issuances in 2015 as compared with 2014;

· $16 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs; and

· $39 million decrease in distributions paid to non-controlling interest due to the Partnership’s 100 percent ownership in GTN and Bison effective April 1, 2015 and October 1, 2014, respectively.

Capital spending

The Partnership’s share in capital spending for maintenance of existing facilities and growth projects was as follows:

Year Ended December 31 (millions of dollars) (unaudited)	2016 (a)	2015 (a)	2014 (a)
Maintenance	31	21	18
Growth	5	54	4
Total (b)	36	75	22

(a) Financial information was recast to reflect our 61.71 percent share of PNGTS’ capital spending for all periods presented however, PNGTS did not incur significant capital expenditures for all the periods presented. Please see “Basis of Presentation” section for more information.

(b) Total maintenance and growth capital expenditures as reflected in this table include amounts attributable to the Partnership’s proportionate share of maintenance and growth capital expenditures of the Partnership’s equity investments, which are not reflected in our total capital expenditures as presented in our consolidated statement of cash flows.

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

Maintenance capital spending increased by $10 million in 2016 compared to 2015 mainly due to major overhauls conducted in 2016 on Northern Border and Great Lakes and costs related to pipe integrity on Great Lakes and North Baja.

In 2015, The Partnership incurred significant spending related to the construction of Carty Lateral. No such significant project occurred in 2016.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

Overall capital spending increased by $53 million in 2015 compared to 2014 mainly due to the cost incurred on the construction of Carty Lateral, which was placed in service in October 2015.

Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its December 2016 distribution of $16 million on January 9, 2017, of which the Partnership received its 50 percent share or $8 million. The distribution was paid on January 31, 2017.

Northern Border declared its January 2017 distribution of $18 million on February 15, 2017, of which the Partnership received its 50 percent share or $9 million on February 28, 2017.

Northern Border declared its February 2017 distribution of $9 million on March 10, 2017, of which the Partnership received its 50 percent share or $5 million on March 31, 2017.

Northern Border declared its March 2017 distribution of $13 million on April 7, 2017, of which the Partnership received its 50 percent share or $7 million on April 28, 2017.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes declared its fourth quarter 2016 distribution of $14 million on January 9, 2017, of which the Partnership received its 46.45 percent share or $7 million. The distribution was paid on February 1, 2017.

Great Lakes declared its first quarter 2017 distribution of $43 million on April 19, 2017, of which the Partnership received its 46.45 percent share or $20 million. The distribution was paid on May 1, 2017.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 1, 2017.

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

Investing Cash Flow Outlook

The Partnership expects to fund $9 million contribution in 2017 to fund debt repayments of Great Lakes which is consistent with prior years.

In 2017, our pipeline systems, which includes Iroquois, expect to invest approximately $95 million in maintenance of existing facilities and approximately $7 million in growth projects, of which the Partnership’s share would be $64 million and $3 million, respectively. Our consolidated entities have commitments of $1 million as of December 31, 2016 in connection with various maintenance and general plant projects.

Financing Cash Flow Outlook

On January 23, 2017, the board of directors of our General Partner declared the Partnership’s fourth quarter 2016 cash distribution in the amount of $0.94 per common unit which was paid on February 14, 2017 to unitholders of record as of February 2, 2017.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million which was paid on February 14, 2017. The Class B distribution represents an amount equal to 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less the threshold level of $20 million. For 2017, the threshold level is the same and we anticipate such threshold will be exceeded in the third quarter of 2017.

On April 25, 2017, the board of directors of our General Partner declared the Partnership’s first quarter 2017 cash distribution in the amount of $0.94 per common unit and was paid on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million of IDRs.

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition. The indenture for the notes contains customary investment grade covenants.

Please read Notes 6, 9, 12 and 13, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow

EBITDA is an approximate measure of our operating cash flow during the current earnings period and reconciles directly to the most comparable measure of net income. It measures our earnings before deducting interest, depreciation and amortization, net income attributable to non-controlling interests, and it includes earnings from our equity investments. Our Adjusted EBITDA excludes the impact of the $199 million non-cash impairment charge we recognized in fourth quarter 2015 on our investment in Great Lakes. We believe the charge is significant but not reflective of our underlying operations.

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period and reconcile directly to the net income amount presented.

Reconciliations of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow

The following table presents a reconciliation of the non-GAAP financial measures of EBITDA, Adjusted EBITDA and Distributable Cash Flow, to the GAAP financial measure of net income.

Year Ended December 31 (unaudited)
(millions of dollars)	2016 (a)		2015 (a)		2014 (a)
Net income	263		58		241

Add:
Interest expense (b)	73		68		62
Depreciation and amortization	96		95		96
Income taxes	1		2		2
EBITDA	433		223		401

Impairment of equity investment	—		199		—

Adjusted EBITDA	433		422		401

Add:
Distributions from equity investments (c)
Northern Border	91		91		88
Great Lakes	34		40		29
	125		131		117
Less:
Equity earnings:
Northern Border	(69	)	(66	)	(69	)
Great Lakes	(28	)	(31	)	(19	)
	(97	)	(97	)	(88	)
Less:
Equity AFUDC	—		(1	)	—
Interest expense (b)	(73	)	(68	)	(62	)
Income taxes	(1	)	(2	)	(2	)
Distributions to non-controlling interests (d)	(18	)	(29	)	(69	)
Distributions to TransCanada as PNGTS’ former parent(e)	(6	)	(30	)	(29	)
Maintenance capital expenditures (f)	(16	)	(16	)	(8	)
	(114	)	(146	)	(170	)

Total Distributable Cash Flow (j)	347		310		260
General Partner distributions declared (h)	(12	)	(8	)	(5	)
Distributions allocable to Class B units (i)	(22	)	(12	)	—
Distributable Cash Flow (j)	313		290		255

(a) Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b) Interest expense as presented includes net realized loss related to the interest rates swaps and amortization of realized loss on PNGTS’ derivative instruments. See Notes 11 and 18, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more information.

(c) These amounts are calculated in accordance with the cash distribution policies of these entities. Distributions from each of our equity investments represent our respective share of these entities’ quarterly distributable cash during the current reporting period.

(d) Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash not owned by us during the periods presented.

(e) Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash not owned by us during the periods presented.

(f) The Partnership’s maintenance capital expenditures include cash expenditures made to maintain, over the long term, our assets’ operating capacity, system integrity and reliability. Accordingly, this amount represents the Partnership’s and its consolidated subsidiaries’ maintenance capital expenditures and does not include the Partnership’s share of maintenance capital expenditures on our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash.

Please read the Capital spending section for more information regarding the Partnership’s total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.

(g) Distributions declared to the General Partner for the year ended December 31, 2016 included an incentive distribution of approximately $6 million (2015 - $2 million; 2014 - $1 million).

(h) During the twelve months ended December 31, 2016, 30 percent of GTN’s total distributions was $42 million; therefore the distributions allocable to the Class B units was $22 million, representing the amount that exceeded the threshold level of $20 million. During the nine months ended December 31, 2015, 30 percent of GTN’s total distributions was $27 million; therefore the distributions allocable to the Class B units was $12 million, representing the amount that exceeded the threshold level of $15 million. The Class B distribution is determined and payable annually.

(i) On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million which was paid on February 14, 2017. The 2015 Class B distribution amounting to $12 million was paid by the Partnership on February 12, 2016. Please read Notes 6,9,12 and 13, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

(j) “Total Distributable Cash Flow” and “Distributable Cash Flow” represent the amount of distributable cash generated by the Partnership’s subsidiaries and equity investments during the current earnings period and thus reconcile directly to the net income amount presented. The calculation differs from the previous 2014 non-GAAP measures “Partnership Cash Flows before General Partner distributions” and “Partnership Cash Flows” as the previously used measures primarily reflected cash received during the period through distributions from our subsidiaries and equity investments that were generated from the prior quarter’s financial results. The 2014 amounts reflected here have been adjusted to reflect the calculation as described above and to present the comparable “Total Distributable Cash flow” and “Distributable Cash Flow” from the previous periods.

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

EBITDA increased by $210 million to $433 million in 2016 compared to $223 million in 2015. The increase was primarily the result of the recognition of a $199 million non-cash impairment charge in 2015 to our investment in Great Lakes which lowered EBITDA in 2015 accordingly (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

Adjusted EBITDA increased by $11 million compared to the same period in 2015 mainly due to higher transmission revenues as discussed in more detail in the Results of Operations section.

Distributable cash flow increased by $23 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:

· the cash impact of higher Adjusted EBITDA;

· lower distributable cash flow from our equity investments as a result of higher maintenance capital in 2016 as discussed in more detail on the “Capital Spending” section;

· lower distributions paid to non-controlling interests due to the Partnership owning 100 percent of GTN effective April 1, 2015 and

· lower distributable cash flow allocable to TransCanada as the former parent of PNGTS due to the Partnership’s acquisition of 49.9 percent interest in PNGTS from TransCanada effective January 1, 2016;

· higher interest expense related to higher borrowings as a result of the recent acquisitions offset by ;

· higher General Partner distributions due to higher IDRs in the current period; and

· higher distributions allocable to the Class B units during the current period.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

EBITDA decreased by $178 million to $223 million in 2015 compared to $401 million in 2014. The decrease was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015 (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

Adjusted EBITDA increased by $21 million compared to the same period in 2014 due higher transmission revenues and higher earnings from our equity investments as discussed in more detail in the Results of Operations section.

Distributable cash flow increased by $35 million in the twelve months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

· the cash impact of higher Adjusted EBITDA from our subsidiaries and equity investments;

· lower distributions to non-controlling interests as a result of the Partnership owning 100 percent of GTN beginning April 1, 2015 and 100 percent of Bison beginning October 1, 2014;

· higher maintenance capital expenditures primarily due to major compression equipment overhauls on GTN’s pipeline system in 2015;

· higher interest expense related to additional borrowings to fund recent acquisitions;

· higher General Partner distributions due to higher IDRs in the current period; and

· distributions allocable to the Class B units during the current period.

Contractual Obligations

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations as of December 31, 2016 included the following:

	Payments Due by Period
(millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years
Senior Credit Facility due 2021	160	—	—	160	—
2013 Term Loan Facility due 2018	500	—	500	—	—
2015 Term Loan Facility due 2018	170	—	170	—	—
5.90% Senior Notes due in 2018	53	29	24	—	—
4.65% Senior Notes due 2021	350	—	—	350	—
4.375% Senior Notes due 2025	350	—	—	—	350
5.29% Senior Notes due 2020	100	—	—	100	—
5.69% Senior Notes due 2035	150	—	—	—	150
Unsecured Term Loan Facility due 2019	65	10	55	—	—
Unsecured Term Loan due 2019	10	1	9	—	—
3.82% Series D Senior Notes due 2017	12	12	—	—	—
Interest on Debt Obligations (b)	439	69	120	82	168
Operating Leases	9	1	2	1	5
	2,368	122	880	693	673

(a) Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b) Interest payments on floating-rate debt are estimated using interest rates effective as of December 31, 2016.

On November 10, 2016, the Partnership’s Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $160 million was outstanding at December 31, 2016 (December 31, 2015 - $200 million), leaving $340 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be lenders’ base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility was 1.92 percent at December 31, 2016 (December 31, 2015 - 1.50 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing on July 1, 2018. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.000 percent for LIBOR borrowings and 0.125 percent and 1.000 percent for base rate borrowings.

As of December 31, 2016, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent ( 2015 - 2.79 percent) . Prior to hedging activities, the LIBOR-based interest rate was 1.87 percent at December 31, 2016 (December 31, 2015 — 1.50 percent).

On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015. The 2015 Term Loan Facility matures on October 1, 2018. The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.77 percent at December 31, 2016 (December 31, 2015 — 1.39 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.01 to 1.00 as of December 31, 2016.

The Senior Credit Facility and the Term Loan Facilities contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the Term Loan Facilities may become immediately due and payable.

On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2016, the debt service coverage ratio was 2.41 for the twelve preceding months and 1.43 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

On June 1, 2015, GTN’s 5.09 percent unsecured Senior Notes matured. Also, on June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility), which requires yearly principal payments until its maturity on June 1, 2019. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 1.57 percent at December 31, 2016 (December 31, 2015 — 1.19 percent). GTN’s Unsecured Senior Notes, along with this new Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at December 31, 2016 is 44.5 percent.

Tuscarora’s Series D Senior Notes, which require yearly principal payments until maturity, are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. The Series D Senior Notes contain a covenant that limits total debt to no greater than 45 percent of Tuscarora’s total capitalization. Tuscarora’s total debt to total capitalization ratio at December 31, 2016 was 21.22 percent. Additionally, the Series D Senior Notes require Tuscarora to maintain a Debt Service Coverage Ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than 3.00 to 1.00. The ratio was 4.15 to 1.00 as of December 31, 2016.

On April 29, 2016, Tuscarora entered into a $9.5 million unsecured variable rate term loan facility which requires yearly principal payments until its maturity on April 29, 2019. The variable interest is based on LIBOR plus an applicable margin and was 1.90 percent at December 31, 2016.

At December 31, 2016, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s long-term debt at December 31, 2016 was $1,963 million. As of February 28, 2017, the Partnership had $120 million outstanding under the Senior Credit Facility.

Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations as of December 31, 2016 included the following:

	Payments Due by Period (a)
(millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years

7.50% Senior Notes due 2021	250	—	—	250	—
$200 million Credit Agreement due 2020	181	—	—	181	—
Interest payments on debt	103	22	44	37	—
Operating leases (b)	55	3	5	5	42
	589	25	49	473	42

(a) Represents 100 percent of Northern Border’s contractual obligations.

(b) Future minimum payments for office space and rights-of-way under non-cancelable operating leases

Northern Border has commitments of $8 million as of December 31, 2016 in connection with various pipeline, metering and overhaul projects.

Senior Notes

All of Northern Border’s outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums. The indentures for the notes do not limit the amount of unsecured debt Northern Border may incur, but do restrict secured indebtedness. At December 31, 2016, Northern Border was in compliance with all of its financial covenants.

At December 31, 2016, the aggregate estimated fair value of Northern Border’s long-term debt was approximately $464 million (2015 — $426 million). In 2016, interest expense related to the senior notes was $23 million (2015 — $25 million; 2014 — $25 million).

Credit Agreement

Northern Border’s credit agreement consists of a $200 million revolving credit facility. At December 31, 2016, $181 million was outstanding leaving $19 million available for future borrowings. At Northern Border’s option, the interest rate on the outstanding borrowings may be the lenders’ base rate or LIBOR plus, in either case, an applicable margin that is based on Northern Border’s long-term unsecured credit ratings. The interest rate on Northern Border’s credit agreement at December 31, 2016 was 1.90 percent (2015 — 1.74 percent). At December 31, 2016, Northern Border was in compliance with all of its financial covenants.

2016 Credit Facility

On November 15, 2016, Northern Border entered into a $100 million 364-day revolving credit facility expiring on November 14, 2017, which utilizes the same covenants as the $200 million revolving credit facility. As a result of the shared covenants, the $200 million revolving credit facility was amended for the second time to include the cross default with the new $100 million 364-day revolving credit facility. At December 31, 2016, the $100 million 364-day revolving credit facility has not been utilized.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations as of December 31, 2016 included the following:

	Payments Due by Period (a)
(millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years

6.73% series Senior Notes due 2016 to 2018	18	9	9	—	—
9.09% series Senior Notes due 2016 to 2021	50	10	20	20	—
6.95% series Senior Notes due 2019 to 2028	110	—	11	22	77
8.08% series Senior Notes due 2021 to 2030	100	—	—	10	90
Interest payments on debt	141	21	38	31	51
	419	40	78	83	218

(a) Represents 100 percent of Great Lakes’ contractual obligations.

Great Lakes has commitments of $1 million as of December 31, 2016 in connection with pipeline integrity and overhaul projects.

Long-Term Financing

All of Great Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $150 million of Great Lakes’ partners’ capital was restricted as to distributions as of December 31, 2016 (2015 — $160 million). Great Lakes was in compliance with all of its financial covenants at December 31, 2016.

The aggregate estimated fair value of Great Lakes’ long-term debt was $354 million at December 31, 2016 (2015 — $362 million). The aggregate annual required repayment of senior notes is $19 million for each year 2017 and 2018 and $21 million for each year 2019 and 2020 and $31 million for 2021. Aggregate required repayments of senior notes thereafter total $167 million. In 2016, interest expense related to Great Lakes’ senior notes was $22 million (2015 - $24 million; 2014 - $25 million).

Other

Great Lakes has a cash management agreement with TransCanada whereby Great Lakes’ funds are pooled with other TransCanada affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’ operating needs. At December 31, 2016 and 2015, Great Lakes has an outstanding receivable from this arrangement amounting to $27 million and $51 million, respectively.

Cash Distribution Policy of the Partnership

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its two percent general partner interest and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The distribution to the General Partner illustrated below, other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two percent general partner interest, represents the IDRs.

			Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount		Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45		98	%	2	%
First Target Distribution	above $0.45	up to $0.81	98	%	2	%
Second Target Distribution	above $0.81	up to $0.88	85	%	15	%
Thereafter	above $0.88		75	%	25	%

The following table provides information about our distributions (in millions, except per unit distributions amounts).

				Limited Partners					General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(c)			2%		IDRs (a)		Total Cash Distribution
1/16/2014	2/14/2014	$	0.81	$	50	$	—		$	1	$	—	$	51
4/25/2014	5/15/2014	$	0.81	$	51	$	—		$	1	$	—	$	52
7/23/2014	8/14/2014	$	0.84	$	53	$	—		$	1	$	—	$	54
10/23/2014	11/14/2014	$	0.84	$	53	$	—		$	1	$	1	$	55
1/22/2015	2/13/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
4/23/2015	5/15/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
7/23/2015	8/14/2015	$	0.89	$	56	$	—		$	2	$	1	$	59
10/22/2015	11/13/2015	$	0.89	$	57	$	—		$	1	$	1	$	59
1/21/2016	2/12/2016	$	0.89	$	57	$	12	(d)	$	1	$	1	$	71
4/21/2016	5/13/2016	$	0.89	$	58	$	—		$	1	$	1	$	60
7/21/2016	8/12/2016	$	0.94	$	62	$	—		$	1	$	2	$	65
10/20/2016	11/14/2016	$	0.94	$	63	$	—		$	1	$	2	$	66
1/23/2017 (b)	2/14/2017 (b)	$	0.94	$	64	$	22	(e)	$	2	$	2	$	90

(a) The distributions paid for the year ended December 31, 2016 included incentive distributions to the General Partner of $6 million (2015 - $2 million, 2014 - $1 million).

(b) On February 14, 2017, we paid a cash distribution of $0.94 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017. Please read Note 23, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures

(c) The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds. Please read Notes 6, 9 and 12,Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

(d) On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN’s total distributable cash flows for the nine months ended December 31, 2015 less $15 million. Please read Notes 6, 9 and 12 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more detailed disclosures on the Class B units.

(e) On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN’s total distributable cash flows for the year ended December 31, 2016 less $20 million Please read Notes 6, 9 and 12, Notes to Consolidated Financial Statements for the year ended December 31, 2016included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

Distribution Policies of Our Pipeline Systems

Distributions of available cash are made to partners on a pro rata basis according to each partner’s ownership percentage, approximately one month following the end of a quarter. Our pipeline systems’ respective management committees determine the amounts and timing of cash distributions, where the amounts of such distributions are based on distributable cash flow as determined by a prescribed formula. Any changes to, or suspension of our pipeline systems’ cash distribution policies requires the unanimous approval of their respective management committees.

GTN, Bison, and North Baja’s distribution policies require the pipelines to distribute 100 percent of distributable cash flow based on earnings before depreciation and amortization less allowance for funds used during construction (AFUDC) and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

Tuscarora’s distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before depreciation and amortization less debt repayment, AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

PNGTS distributes its available cash less any required reserves that are necessary to comply with its debt covenants and/or appropriately conduct its business, as determined and approved by its management committee. While PNGTS debt repayments are not funded with cash calls to its owners, PNGTS has historically funded its scheduled debt repayments by adjusting its available cash for distribution, which effectively reduces the cash available for distributions.

Northern Border’s distribution policy requires Northern Border to distribute on a monthly basis, 100 percent of the distributable cash flow based on earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Northern Border adopted certain changes related to equity contributions that defined minimum equity to total capitalization ratios to be used by the Northern Border management committee to

determine the amount of required equity contributions, timing of the required contributions and for any shortfall due to the inability to refinance maturing debt to be funded by equity contributions.

Great Lakes’ distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before income taxes, depreciation, AFUDC less capital expenditures and debt repayments not funded with cash calls to its partners. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.

We believe our critical accounting estimates discussed in the following paragraphs require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements. These critical accounting estimates should be read in conjunction with our accounting policies summarized on Notes 2 and 3, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K.

Regulation

Our pipeline systems’ accounting policies conform to Accounting Standards Codification (ASC) 980 — Regulated Operations. As a result, our pipeline systems record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Our pipeline systems consider several factors to evaluate their continued application of the provisions of ASC 980 such as potential deregulation of their pipelines; anticipated changes from cost-based ratemaking to another form of regulation; increasing competition that limits their ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs.

Certain assets that result from the ratemaking process are reflected on the balance sheets of our pipeline systems. If it is determined that future recovery of these assets is no longer probable as a result of discontinuing application of ASC 980 or other regulatory actions, our pipeline systems would be required to write off the regulatory assets at that time.

As of December 31, 2016, our equity investees have regulatory assets amounting to $15 million (2015 - $16 million).

As of December 31, 2016, our equity investees have regulatory liabilities amounting to $27 million (2015 - $22 million).

At December 31, 2016, the Partnership had $1 million regulatory assets reported as part of other current assets on the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). As of December 31, 2016, the Partnership had regulatory liabilities of $25 million mostly relating to estimated costs associated with future removal of transmission and gathering facilities or allowed to be collected by FERC in depreciation rates (2015 - $24 million).

Impairment of Equity Investments, Goodwill and Long-Lived Assets

Equity Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

During the fourth quarter of 2015, we determined that our investment in Great Lakes’ long-term value had been adversely impacted by the changing natural gas flows in its market region. Additionally, we concluded that other strategic alternatives to increase its utilization or revenue were no longer feasible. As a result, we determined that the carrying value of our investment in Great Lakes was in excess of its fair value and the decline was not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired.

Our analysis resulted in an impairment charge of $199 million reflected as Impairment of equity-method investment on our Statement of Income for the year ended December 31, 2015. The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net assets, to $260 million. The difference represented the equity method goodwill remaining in our investment in Great Lakes.

The assumptions we used in 2015 related to the estimated fair value of our remaining equity investment in Great Lakes could be negatively impacted by near and long-term conditions including:

· future regulatory rate action or settlement,

· valuation of Great Lakes in future transactions,

· changes in customer demand at Great Lakes for pipeline capacity and services,

· changes in North American natural gas production in the major producing basins,

· changes in natural gas prices and natural gas storage market conditions, and

· changes in other long-term strategic objectives.

Great Lakes’ evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have remained relatively stable during the year ended 2016 and into 2017. Accordingly, our estimation of the fair value of our investment in Great Lakes has not materially changed from 2015. There is a risk that reductions in future cash flow forecasts and other adverse changes in these key assumptions could result in additional future impairment of the carrying value of our investment in Great Lakes.

As of December 31, 2016, no impairment charge has been recorded related to any of our other equity investments.

Goodwill

We test goodwill for impairment annually based on ASC 350 — Intangibles — Goodwill and Other, or more frequently if events or changes in circumstances lead us to believe it might be impaired. We assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired, and if we do not conclude that it is more likely than not that the fair value of the reporting unit is greater than the carrying value, we use a two-step process to test for impairment:

1. First, we compare the fair value of the reporting unit, including its goodwill, to its book value. If the fair value is less than book value, we consider our goodwill to be impaired.

2. Next, we measure the amount of the impairment by calculating the implied fair value of the reporting unit’s goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting unit from the fair value calculated in the first step. If the goodwill’s carrying value exceeds its implied fair value we record an impairment charge.

We base these valuations on our projection of future cash flows which involves making estimates and assumptions about:

· discount rates;

· commodity and capacity prices;

· market supply and demand assumptions;

· growth opportunities;

· output levels;

· competition from other companies;

· regulatory changes; and

· regulatory rate action or settlement.

If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of reporting unit, to the extent of the balance of goodwill.

At December 31, 2016 and 2015, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja and Tuscarora acquisitions. No impairment of goodwill existed at December 31, 2016.

As discussed more fully in Note 20, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K, the reduction in Tuscarora’s future cash flows as a result of the Tuscarora Settlement constituted a triggering event in the second quarter of 2016 that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our second quarter analysis, which was also reviewed for any material updates as part of our annual impairment test on goodwill, resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenues expected from Tuscarora’s current and expected future contracting level. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as expected outcome of future rate proceedings, projected operating costs and estimated rate of return on invested capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

Long-Lived Assets

We assess our long-lived assets for impairment based on ASC 360-10-35 Property, Plant, and Equipment — Overall — Subsequent Measurement when events or changes in circumstances indicate that the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows expected to be generated by that asset or asset group is less than the carrying value of the assets, an impairment charge is recognized for the excess of the carrying value over the fair value of the assets. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals as considered necessary.

Our management evaluates changes in our business and economic conditions and their implications for recoverability of our long-lived assets’ carrying values when assessing these assets for impairments. The development of fair value estimates requires significant judgement in estimating future cash flows. In order to determine the estimated future cash flows, management must make certain estimates and assumptions, which include, but are not limited to, demand, competition, contract renewals and other factors.

Any changes we make to these estimates and assumptions could materially affect future cash flows, which could result to the recognition of an impairment loss in our statement of income.

As of December 31, 2016, there were no indicators of impairment for our long-lived assets.

Contingencies

Our pipeline systems’ accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 — Contingencies. Our pipeline systems base their estimates on currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our pipeline systems’ estimates resulting in an impact, positive or negative, on earnings and cash flow.

CONTINGENCIES

Legal

Various legal actions or governmental proceedings involving our pipeline systems that have arisen in the ordinary course of business are pending. Our pipeline systems believe that the resolution of these issues will not have a material adverse impact on their results of operations or financial position. Please read Part I, Item 3. “Legal Proceedings” of our 2016 Annual Report on Form 10-K dated February 28, 2017 for additional information.

Environmental

We do not believe that compliance with existing environmental laws and regulations will have a material adverse effect on our pipeline systems. Because of the inherent uncertainties as to the final outcome of proposed environmental regulations and legislation, we cannot estimate the range of possible costs, if any, from the proposals. Please read Part I, Item 1. “Business — Government Regulation” of our 2016 Annual Report on Form 10-K dated February 28, 2017 for additional information.

Greenhouse Gas Regulation

Through the EPA, the U.S. Government has imposed various measures related to GHG emissions, including emission monitoring and reporting requirements, preconstruction and operating permits for certain large stationary sources. The EPA has also proposed rules requiring the control of methane emissions from and leak detection and repair requirements for certain oil and natural gas production, processing, transmission and storage activities, as well as leak detection and repair requirements. These final and proposed rules, as well as additional legislation or regulations for the control of GHG emissions could materially increase our operating costs, including our cost of environmental compliance by requiring us to install additional equipment and potentially purchase emission allowances or offset credits. The regulation or restriction of GHG emissions could also result in changes to the consumption and demand for natural gas. This could have either positive or adverse effects on our pipeline systems, our financial position, results of operations and future prospects. Please read Part I, Item 1. “Business — Government Regulation” of our 2016 Annual Report on Form 10-K dated February 28, 2017 for additional information.

RELATED PARTY TRANSACTIONS

Please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence” of our 2016 Annual Report on Form 10-K dated February 28, 2017 and Note 16, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included as exhibit 99.2 of this Current Report on Form 8-K for more information regarding related party transactions.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

The Partnership and our pipeline systems are exposed to market risk, counterparty credit risk and liquidity risk. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

Our primary risk management objective is to mitigate the impact of these risks on earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.

We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

MARKET RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

As of December 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Facility and Tuscarora’s Unsecured Term Facility, under

which $405 million, or 21 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of December 31, 2015, the Partnership’s interest rate exposure results from our floating rate Senior Credit Facility, the unhedged portion ($350 million) of our 2013 Term Loan Facility, our 2015 Term Loan Facility and GTN’s Unsecured Term Facility, under which $795 million, or 40 percent, of our outstanding debt was subject to variability in LIBOR interest rates.

As of December 31, 2016, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent. If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at December 31, 2016, The Partnership’s annual interest expense on its remaining debt with variable interest exposure would increase (decrease) and net income would decrease (increase) by approximately $4 million.

As of December 31, 2016, $181 million, or 42 percent of Northern Border’s outstanding debt was at floating rates (2015 — $61 million or 15 percent). If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at December 31, 2016, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $2 million.

GTN’s Unsecured Senior Notes, Northern Border’s Senior Notes, Tuscarora’s Series D Senior Notes and all of Great Lakes’ and PNGTS’ notes represent fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison and North Baja, as they currently do not have any debt.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

· Swaps — contractual agreements between two parties to exchange streams of payments over time according to specified terms.

· Options — contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.

The Partnership and our pipeline systems enter into interest rate swaps and option agreements to mitigate the impact of changes in interest rates.

The interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). At December 31, 2015, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $1 million both on a gross and net basis. The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the years ended December 31, 2016, 2015 and 2014. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $2 million for the year ended December 31, 2016 (2015 —nil million, 2014 — loss of $1 million). In 2016, the net realized loss related to the interest rate swaps was $3 million, and was included in financial charges and other (2015 — $2 million, 2014 - $2 million).

The Partnership has no master netting agreements, however, contracts contain provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be net asset of nil million as of December 31, 2016 and there would be no effect on the consolidated balance sheet as of December 31, 2015.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCL as of the termination date. The previously recorded AOCL is currently being amortized against earnings over the life of the PNGTS’ 5.90% Senior Secured Notes. At December 31, 2016, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCL was $2 million (2015 - $2 million). For the year ended December 31, 2016, 2015 and 2014, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.