Exhibit 99.6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the Unaudited Consolidated Financial Statements and Notes thereto for quarter ended March 31, 2017 included as Exhibit 99.5 of this Current Report on Form 8-K, as well as our 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.

BASIS OF PRESENTATION

See the Basis of Presentation section of Note 2- Significant Accounting Policies, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 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 was 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 18-Subsequent Events, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K). This transaction was accounted prospectively and did not form part of the accompanying financial information.

RECENT BUSINESS DEVELOPMENTS

Cash Distributions –

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.

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 (2017 Rate Case). 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.

HOW WE EVALUATE OUR OPERATIONS

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

EBITDA

We use EBITDA as a proxy of our operating cash flow and current operating profitability.

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 and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

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

	Three months ended
(unaudited)	March 31,				$		%
(millions of dollars)	2017 (a)		2016 (a)		Change*		Change*

Transmission revenues	112		111		1		**
Equity earnings	36		33		3		9
Operating, maintenance and administrative costs	(23	)	(21	)	(2	)	(10	)
Depreciation	(24	)	(23	)	(1	)	(4	)
Financial charges and other	(17	)	(18	)	1		6
Net income before taxes	84		82		2		2

Income taxes	(1	)	(1	)	—		—
Net income	83		81		2		2

Net income attributable to non-controlling interest	6		7		1		14
Net income attributable to controlling interests	77		74		3		4

* Positive number represents a favorable change; bracketed or negative number represents an unfavorable change

** less than 1 percent change

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

Three Months Ended March 31, 2017 compared to Same Period in 2016

Net income attributable to controlling interests - The Partnership’s net income attributable to controlling interests increased by $3 million or 4 percent mainly due to higher revenues and equity earnings partially offset by higher costs.

Transmission revenues - The $1 million increase was primarily due to higher transportation revenues on GTN offset by lower discretionary revenues on PNGTS.

Equity Earnings - The $3 million increase was primarily due to higher equity earnings on our investment in Great Lakes primarily due to its higher transportation revenues.

Operating, maintenance and administrative costs - The $2 million increase was mainly attributable to higher operational costs on GTN.

Net Income Attributable to Common Units and Net Income per Common Unit

As discussed in Note 7 within Item 1. “Financial Statements,” we will allocate a portion of the Partnership’s income to the Class B Units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Currently, we expect to allocate a portion of the Partnership’s income to the Class B units beginning in the third quarter of 2017.

Please read also Note 6-Partner’s Equity, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K, for additional disclosures on the Class B units.

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 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

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

Total capacity under the Senior Credit Facility	500	500	500
Less: Outstanding borrowings under the Senior Credit Facility	170	110	160
Available capacity under the Senior Credit Facility	330	390	340

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.

Cash Flow Analysis for the Three Months Ended March 31, 2017 compared to Same Period in 2016

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)		2016 (a)

Net cash provided by (used in):
Operating activities	107		120
Investing activities	(11	)	(208	)
Financing activities	(83	)	102
Net increase in cash and cash equivalents	13		14
Cash and cash equivalents at beginning of the period	64		55
Cash and cash equivalents at end of the period	77		69

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

Operating Cash Flows

Net cash provided by operating activities decreased by $13 million in the three months ended March 31, 2017 compared to the same period in 2016 primarily due to lower distributions from Great Lakes in 2017. Distributions received in the first quarter of 2016 from Great Lakes were higher than on a run-rate basis due to the resolution of certain regulatory proceedings in the fourth quarter of 2015 which inflated its results during that period and resulted in higher cash flow which was paid to the Partnership in the first quarter of 2016 and not applicable in the first quarter of 2017.

Investing Cash Flows

Net cash used in investing activities decreased by $197 million in the three months ended March 31, 2017 compared to the same period in 2016. On January 1, 2016, we invested $193 million to acquire a 49.9 percent interest in PNGTS and there were no large capital expenditures in the three months ended March 31, 2017.

Financing Cash Flows

Net cash provided by financing activities decreased by $185 million in the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the net effect of:

· $195 million decrease in issuances of debt;

· $31 million increase in debt repayments;

· $52 million increase in ATM equity issuances;

· $8 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs;

· $5 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; and

· $10 million increase in distributions paid to Class B units.

Cash Flow Outlook

Operating Cash Flow Outlook

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. The distribution was paid 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 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 made an equity contribution to Great Lakes of $4 million in the first quarter of 2017. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2017 to further fund debt repayments. This is consistent with prior years.

Our consolidated entities have commitments of $1 million as of March 31, 2017 in connection with various maintenance and general plant projects.

Our expected total growth and maintenance capital expenditures as outlined in our Management Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2016 Consolidated Financial Statements and Notes thereto included as Exhibit 99.3 of this Current Report on Form 8-K remain unchanged.

Financing Cash Flow Outlook

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 see “Recent Business Developments section.”

Non-GAAP Financial Measures: 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 includes earnings from our equity investments.

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.

Total distributable cash flow includes EBITDA plus:

· Distributions from our equity investments

less:

· Earnings from our equity investments,

· Equity allowance for funds used during construction (Equity AFUDC),

· Interest expense,

· Distributions to non-controlling interests;

· Distributions to TransCanada as the former parent of PNGTS; and

· Maintenance capital expenditures from consolidated subsidiaries.

Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its effective two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units in 2017 equal 30 percent of GTN’s distributable cash flow less $20 million. Distributable cash flow and EBITDA are performance measures presented to assist investors’ in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating performance. The non-GAAP measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.

Reconciliations of Non-GAAP Financial Measures

The following table represents a reconciliation of the non-GAAP financial measures of EBITDA, total distributable cash flow and distributable cash flow, to the most directly comparable GAAP financial measure of Net Income:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)		2016(a)
Net income	83		81

Add:
Interest expense	17		18
Depreciation and amortization	24		23
Income taxes	1		1

EBITDA	125		123

Add:
Distributions from equity investments (b)
Northern Border	20		23
Great Lakes	20		17
	40		40
Less:
Equity earnings:
Northern Border	(19	)	(18	)
Great Lakes	(17	)	(15	)
	(36	)	(33	)
Less:
Interest expense	(17	)	(18	)
Income taxes	(1	)	(1	)
Distributions to non-controlling interest (c)	(5	)	(9	)
Distributions to TransCanada as PNGTS’ former parent(d)	(1	)	(2	)
Maintenance capital expenditures (e)	(10	)	(1	)
	(34	)	(31	)

Total Distributable Cash Flow	95		99
General Partner distributions declared (f)	(3	)	(2	)
Distributions allocable to Class B units (g)	—		—
Distributable Cash Flow	92		97

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

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

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

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

(e) The Partnership’s maintenance capital expenditures include cash expenditures incurred or cash reserved to maintain, over the long term, the operating capacity, system integrity and reliability of our pipeline assets. 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 for 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.

(f) Distributions declared to the General Partner for the three months ended March 31, 2017 included an incentive distribution of approximately $2 million (March 31, 2016 — $1 million).

(g) During the three months ended March 31, 2017, 30 percent of GTN’s total eligible distributions was $10 million (March 31, 2016 - $11 million), therefore, no distributions were allocated to the Class B units as the threshold level of $20 million has not been exceeded. Consistent with 2016, we expect the 2017 threshold will be exceeded in the third quarter of 2017.

Please read Notes 6 and 7, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K for additional disclosures on the Class B units.

First Quarter 2017 Compared with First Quarter 2016

Our EBITDA increased by $2 million as a result of higher revenues and equity earnings partially offset by an increase in GTN’s operational costs as discussed in the “Results of Operations” section. However, our distributable cash flow decreased by $5 million in the first quarter of 2017 compared to the same period in 2016 due to higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system and cash reserved on PNGTS’ pipeline integrity program that is currently being implemented on its pipeline system.

Contractual Obligations

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations related to debt as of March 31, 2017 included the following:

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2017
TC PipeLines, LP
Senior Credit Facility due 2021	110	—	—	110	—	2.03	%
2013 Term Loan Facility due July 2018	500	—	500	—	—	2.03	%
2015 Term Loan Facility due September 2018	170	—	170	—	—	1.93	%
4.65% Senior Notes due 2021	350	—	—	350	—	4.65	%(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	—	—	100	—	5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69	%(a)
Unsecured Term Loan Facility due 2019	65	10	55	—	—	1.73	%
PNGTS
5.90% Senior Secured Notes due 2018	41	23	18	—	—	5.90	(a)
Tuscarora
Unsecured Term Loan due 2019	10	1	9	—	—	1.91	%
3.82% Series D Senior Notes due 2017	12	12	—	—	—	3.82	%(a)
	1,858	46	752	560	500

(a) Fixed interest rate

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Refer to Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the derivatives.

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 debt at March 31, 2017 was $1,905 million.

Please read Note 5, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K for additional information regarding the Partnership’s debt.

Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations related to debt as of March 31, 2017 included the following:

	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2017
$200 million Credit Agreement due 2020	181	—	—	181	—	1.91	%
7.50% Senior Notes due 2021	250	—	—	250	—	7.50	%(b)
	431	—	—	431	—

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

(b) Fixed interest rate

As of March 31, 2017, $181 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $19 million available for future borrowings. At March 31, 2017, Northern Border was in compliance with all of its financial covenants.

As of March 31, 2017, Northern Border had not utilized the $100 million 364-day revolving credit facility.

Northern Border has commitments of $3 million as of March 31, 2017 in connection with compressor station overhaul projects and other capital projects.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations related to debt as of March 31, 2017 included the following:

	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2017
6.73% series Senior Notes due 2017 to 2018	9	9	—	—	—	6.73	%(b)
9.09% series Senior Notes due 2017 and 2021	50	10	20	20	—	9.09	%(b)
6.95% series Senior Notes due 2019 and 2028	110	—	22	22	66	6.95	%(b)
8.08% series Senior Notes due 2021 and 2030	100	—	—	20	80	8.08	%(b)
	269	19	42	62	146

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

(b) Fixed interest rate

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $145 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2017 (December 31, 2016 — $150 million). Great Lakes was in compliance with all of its financial covenants at March 31, 2017.

Great Lakes has commitments of $1 million as of March 31, 2017 in connection with pipeline integrity, major overhaul projects, and right of way renewals.

Critical Accounting Policies and 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. There were no

significant changes to the Partnership’s critical accounting estimates during the three months ended March 31, 2017. Information about our critical accounting estimates is included in the Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K

Our significant accounting policies have remained unchanged since December 31, 2016 except as described in Note 3, Notes to Consolidated Financial Statements and Notes thereto for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K. A summary of our significant accounting policies can be found in the Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K.

RELATED PARTY TRANSACTIONS

Please read Note 10 and 18, Notes to Consolidated Financial Statements for quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K for additional information regarding related party transactions.

Item 3. 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 floating rate 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 March 31, 2017, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $355 million, or 19 percent, of our outstanding debt was subject to variability in LIBOR interest rates. 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 Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $405 million or 21 percent of our outstanding debt was subject to variability in LIBOR interest rates.

As of March 31, 2017, 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 March 31, 2017, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $4 million.

As of March 31, 2017 and December 31, 2016, $181 million, or 42 percent, of Northern Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at March 31, 2017, 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 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 March 31, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2 million (both on a gross and net basis). 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). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three months ended March 31, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $1 million for the three months ended March 31, 2017 (2016 — loss of $2 million). For the three months ended March 31, 2017, the net realized loss related to the interest rate swaps was nil million and was included in financial charges and other (2016 — nil million).

The Partnership has no master netting agreements; however, it has derivative contracts containing 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 no effect on the consolidated balance sheet as of March 31, 2017 (net asset of nil million as of December 31, 2016).

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 Senior Secured Notes. At March 31, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCL was $2 million (December 31, 2016 - $2 million). For the quarter ended March 31, 2017 and 2016, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil million.

OTHER RISKS

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems. The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers’ creditworthiness.

Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2017, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At March 31, 2017, we had a credit risk concentration on one of our customers, Anadarko Energy Services Company, which owed us approximately $4 million and this amount represented greater than 10 percent of our trade accounts receivable.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At March 31, 2017, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $110 million. In addition, at March 31, 2017, Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $181 million drawn and an additional $100 million 364-day revolving credit facility with no current borrowings. Both the Senior Credit Facility and the Northern Border $200 million credit facility have accordion features for additional capacity of $500 million and $100 million respectively, subject to lender consent.