TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

December 31 (millions of dollars)	2016(a)		2015(a)

ASSETS
Current Assets
Cash and cash equivalents	64		55
Accounts receivable and other (Note 19)	47		41
Inventories	7		7
Other	7		3
	125		106
Equity investments (Note 4)	918		965
Plant, property and equipment, net (Note 5)	2,180		2,257
Goodwill	130		130
Other assets (Note 3)	1		1
	3,354		3,459

LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	29		34
Accounts payable to affiliates (Note 16)	8		8
Accrued interest	10		8
Distributions payable	3		10
Current portion of long-term debt (Note 7)	52		36
	102		96
Long-term debt (Note 7)	1,859		1,935
Deferred state income taxes (Note 23)	10		10
Other liabilities (Note 8)	28		27
	1,999		2,068

Common units subject to rescission (Note 9)	83		—

Partners’ Equity (Note 9)
Common units	1,002		1,021
Class B units	117		107
General partner	27		25
Accumulated other comprehensive loss (AOCL)(Note 10)	(2	)	(4	)
Controlling interests	1,144		1,149
Non—controlling interest	97		91
Equity of former parent of PNGTS	31		151
	1,272		1,391
	3,354		3,459

Contingencies (Note 21)
Variable Interest Entities (Note 22)
Subsequent Events (Note 24)

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

Year ended December 31 (millions of dollars except per common unit amounts)	2016(a)			2015(a)			2014(a)

Transmission revenues	426			417			410
Equity earnings (Note 4)	97			97			88
Impairment of equity-method investment (Note 4)	—			(199		)	—
Operation and maintenance expenses	(58		)	(61		)	(61		)
Property taxes	(27		)	(27		)	(28		)
General and administrative	(7		)	(9		)	(9		)
Depreciation	(96		)	(95		)	(96		)
Financial charges and other (Note 11)	(71		)	(63		)	(61		)
Net income before taxes	264			60			243

Income taxes (Note 23)	(1		)	(2		)	(2		)
Net Income	263			58			241

Net income attributable to non-controlling interests	15			21			46
Net income attributable to controlling interests	248			37			195

Net income (loss) attributable to controlling interest allocation (Note 12)
Common units	211			(2		)	168
General Partner	11			3			4
TransCanada and its subsidiaries	26			36			23
	248			37			195

Net income (loss) per common unit (Note 12) — basic and diluted (b)	$	3.21		$	(0.03	)	$	2.67

Weighted average common units outstanding (millions) — basic and diluted	65.7			63.9			62.7

Common units outstanding, end of year (millions)	67.4			64.3			63.6

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

Net income	263		58	241
Other comprehensive income
Change in fair value of cash flow hedges (Notes 10 and 18)	3		—	(1	)
Reclassification to net income of gains and losses on cash flow hedges (Note 10)	(2	)	—	—
Amortization of realized loss on derivative instrument (Notes 10 and 18)	1		1	1
Comprehensive income	265		59	241
Comprehensive income attributable to non-controlling interests	16		21	46
Comprehensive income attributable to controlling interests	249		38	195

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

(b) Net income per common unit prior to recast (Refer to Note 2).

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31 (millions of dollars)	2016 (a)		2015 (a)		2014 (a)
Cash Generated From Operations
Net income	263		58		241
Depreciation	96		95		96
Impairment of equity-method investment (Note 4)			199		—
Amortization of debt issue costs reported as interest expense (Note 11)	2		1		1
Amortization of realized loss on derivative instrument (Note 18)	1		1		1
Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 6)	—		2		—
Equity earnings from equity investments (Note 4)	(97	)	(97	)	(88	)
Distributions received from operating activities of equity investments (Note 3)	153		119		115
Provision for deferred state income taxes (Note 23)	—		4		(1	)
Provision for rate refund (Note 2)	—		(101	)	23
Equity allowance for funds used during construction	—		(1	)	—
Change in operating working capital (Note 14)	(1	)	(20	)	29
	417		260		417
Investing Activities
Investment in Great Lakes (Note 4)	(9	)	(9	)	(9	)
Acquisition of 49.9 percent interest in PNGTS (Note 6)	(193	)	—		—
Acquisition of the remaining 30 percent interest in GTN (Note 6)	—		(264	)	—
Acquisition of the remaining 30 percent interest in Bison (Note 6)	—		—		(217	)
Adjustment to the 2013 Acquisition	—		—		(25	)
Capital expenditures	(29	)	(54	)	(10	)
Other	1		1		—
	(230	)	(326	)	(261	)
Financing Activities
Distributions paid (Note 13)	(250	)	(228	)	(212	)
Distributions paid to Class B units (Note 9 and 13)	(12	)	—		—
Distributions paid to non-controlling interests	(12	)	(21	)	(60	)
Distributions paid to former parent of PNGTS	(9	)	(19	)	(16	)
Common unit issuance, net (Note 9)	84		44		73
Common unit issuance subject to rescission, net (Note 9)	83		—		—
Equity contribution by the General Partner (Note 6)	—		2		—
Long-term debt issued, net of discount (Note 7)	209		618		35
Short-term loan issued (Note 7)	—		—		170
Long-term debt repaid (Note 7)	(270	)	(425	)	(109	)
Debt issuance costs	(1	)	(3	)	—
	(178	)	(32	)	(119	)
Increase/(decrease) in cash and cash equivalents	9		(98	)	37
Cash and cash equivalents, beginning of year	55		153		116
Cash and cash equivalents, end of year	64		55		153

Interest payments paid	66		59		53
State income taxes paid	2		2		—

Supplemental information about non-cash investing and financing activities
Accrual for costs related to construction of GTN’s Carty Lateral (Note 14)	—		10		—
Issuance of Class B units to TransCanada (Note 9)	—		95		—

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

	Limited Partners						General				Non- Controlling		PNGTS		Total Equity
	Common Units			Class B Units			Partner		AOCL (a) (c)		Interest (d)		(c) (d)		(d)
	(millions of units)	(millions of dollars)		(millions of units)	(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)
Partners’ Equity at December 31, 2013 (d)	62.3	1,322		—	—		28		(5	)	526		142		2,013
Net income (d)	—	168		—	—		4		—		46		23		241
Other Comprehensive Loss, net(d)	—	—		—	—		—		—		—				—
ATM Equity Issuance, net (Note 9)	1.3	71		—	—		2		—		—				73
Acquisition of the remaining interest in Bison (Note 6)	—	(29	)	—	—		—		—		(188	)			(217	)
Distributions (d)	—	(207	)	—	—		(5	)	—		(61	)	(19	)	(292	)
Partners’ Equity at December 31, 2014 (d)	63.6	1,325		—	—		29		(5	)	323		146		1,818
Issuance of Class B Units (Note 6 and 9)	—	—		1.9	95		—		—		—				95
Net income (loss) (d)	—	(2	)	—	12		3		—		21		24		58
Other Comprehensive Loss, net(d)	—	—		—	—		—		1		—				1
ATM Equity Issuance, net (Note 9)	0.7	43		—	—		1		—		—				44
Acquisition of the remaining interest in GTN (Note 6)	—	(124	)	—	—		(3	)	—		(232	)			(359	)
Equity Contribution (Note 6)	—	—		—	—		2		—		—				2
Distributions (d)	—	(221	)	—	—		(7	)	—		(21	)	(19	)	(268	)
Partners’ Equity at December 31, 2015(d)	64.3	1,021		1.9	107		25		(4	)	91		151		1,391
Net income (d)	—	211		—	22		11		—		15		4		263
Other Comprehensive Income, net(d)	—	—		—	—		—		2		1				3
Common unit issuance subject to rescission, net (b) (Note 9)	1.6	81		—	—		2		—		—				83
Reclassification of common unit issuance subject to rescission, net (b) (Note 9)		(81	)	—	—		(2	)	—		—				(83	)
ATM Equity Issuance, net (Note 9)	1.5	82		—	—		2		—		—				84
Acquisition of 49.9 percent interest in PNGTS (Note 6)	—	(72	)	—	—		(1	)	—		—				(73	)
Distributions (d)	—	(240	)	—	(12	)	(10	)	—		(10	)	(4	)	(276	)
Former parent carrying amount of PNGTS(d)													(120	)	(120	)
Partners’ Equity at December 31, 2016(d)	67.4	1,002		1.9	117		27		(2	)	97		31		1,272

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada Corporation (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America.

The Partnership owns interests in the following natural gas pipeline systems through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership:

Pipeline	Length	Description	Ownership
Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TransQuebec and Maritimes Pipeline (TQM) at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS.	61.71 percent (a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent).	49.34 percent (b)

(a) On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 24-Subsequent Events).

(b) Effective June 1, 2017 (Refer to Note 24-Subsequent Events).

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TransCanada. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units,

100 percent of our IDRs and an effective two percent general partner interest in the Partnership at December 31, 2016. TransCanada also indirectly holds an additional 11,287,725 common units, for total ownership of 25.3 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2016 (Refer to Note 6).

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2016 and 2015 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2016, 2015 and 2014. Certain prior year amounts have been reclassified to conform to the current year presentation.

(a) Basis of Presentation

The Partnership consolidates its interests on entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.

Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses that will be consolidated are acquired from TransCanada by the Partnership, the historical financial statements are required to be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented.

When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of acquisition.

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 24-Subsequent Events). As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 24-Subsequent Events). Accordingly, the equity method investment in Iroquois was accounted prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

On April 1, 2015 and October 1, 2014, the Partnership acquired the remaining 30 percent interest in GTN and Bison, respectively, from subsidiaries of TransCanada. These acquisitions resulted in GTN and Bison being wholly-owned by the Partnership. Prior to these transactions, the remaining 30 percent interests held by subsidiaries of TransCanada were reflected as non-controlling interests in the Partnership’s consolidated financial statements. The acquisitions of these already-consolidated entities were accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Refer to Note 6 for additional disclosures regarding these acquisitions.

(b) Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

(c) Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

(e) Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

(f) Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.

(g) Plant, Property and Equipment

Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets’ estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service.

(h) Impairment of Equity Method 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 an 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.

(i) Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

(j) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

(k) Revenue Recognition

Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2016, the Partnership has not recognized any transmission revenue that is subject to possible refund.

For the year ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates . The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS’ final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.

(l) Income Taxes

Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Partnership elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Partnership’s process in determining deferred tax amounts and simplify their presentation. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

(m) Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

(p) Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2016 and 2015.

(q) Government Regulation

The Partnership’s subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators’ decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2016, the Partnership had regulatory assets amounting to $1 million reported as part of other current assets in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 8). AFUDC is capitalized and included in plant, property and equipment.

(r) Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Refer also to Note 3 — Imputation of Interest for the change in accounting policy related to debt issuance costs.

NOTE 3 ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2016

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation, which requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

In October 2016, the FASB issued an updated guidance on consolidation, under which a single decision maker is not required to consider indirect interests held through related parties that are under common control with the single decision maker to be the equivalent of direct interests in their entirety. Instead, a single decision maker is required to include those interests on a proportionate basis consistent with indirect interests held through other related parties. Entities that already have adopted the amendments in February 2015 update are required to apply the amendments in this update retrospectively to all relevant prior periods beginning with the fiscal year in which the amendments were applied. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

Imputation of interest

In April 2015, the FASB issued an amendment of previously issued guidance on imputation of interest, which requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt

issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

As a result of the application of this guidance and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

Earnings per share

In April 2015, the FASB issued an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective on January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

Business combinations

In September 2015, the FASB issued new guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Statement of Cash Flows

In August 2016, the FASB issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance is effective January 1, 2018, however since early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The application of this guidance will not have a material impact on the classification of debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and proceeds from the settlement of corporate owned life insurance. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $25 million and $27 million in 2015 and 2014, respectively, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

Future accounting changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new standard. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify, the cumulative-effect adjustment, if any, on prior period revenues. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

Leases

In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use model (ROU) that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.

The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

Equity method and joint ventures

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

NOTE 4 EQUITY INVESTMENTS

Northern Border and Great Lakes are regulated by FERC and are operated by subsidiaries of TransCanada. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs). Refer to Note 3, Accounting Pronouncements and Note 22, Variable Interest Entities.

	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2016		2016(d)	2015	2014	2016 (d)	2015
Northern Border (a)	50.00	%	69	66	69	444	480
Great Lakes	46.45	%	28	31	19	474	485	(c)
			97	97	88	918	965

(a) Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent in April 2006.

(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the impairment recognized in 2015 on our investment in Great Lakes as discussed below.

(c) During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. See discussion below.

(d) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented (Refer to Note 2).

Northern Border

The Partnership, through its interest in TC PipeLines Intermediate Limited Partnership owns a 50 percent general partner interest in Northern Border. The other 50 percent partnership interest in Northern Border is held by ONEOK Partners, L.P., a publicly traded limited partnership.TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership holds a 98.9899 percent limited partnership interest in TC PipeLines Intermediate Limited Partnership.

Northern Border has a FERC-approved settlement agreement which established maximum long-term transportation rates and charges on the Northern Border system effective January 1, 2013. Northern Border is required to file for new rates no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2016, 2015 and 2014. At December 31, 2016 and 2015, the Partnership had a $116 million difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership’s investment in Northern Border relating to the Partnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border. As of December 31, 2016, no impairment has been identified in our investment in Northern Border.

The summarized financial information for Northern Border is as follows:

December 31 (millions of dollars)	2016		2015

Assets
Cash and cash equivalents	14		27
Other current assets	36		33
Plant, property and equipment, net	1,089		1,124
Other assets (a)	14		16
	1,153		1,200

Liabilities and Partners’ Equity
Current liabilities	38		39
Deferred credits and other	28		26
Long-term debt, net (a), (b)	430		409
Partners’ equity
Partners’ capital	659		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,153		1,200

(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

(b) Includes current maturities of $100 million senior notes at December 31, 2015. During August 2016, the $100 million senior notes were refinanced with a draw on Northern Border’s $200 million revolving credit agreement that expires in 2020.

Year ended December 31 (millions of dollars)	2016		2015		2014

Transmission revenues	292		286		293
Operating expenses	(72	)	(70	)	(72	)
Depreciation	(59	)	(60	)	(59	)
Financial charges and other	(21	)	(22	)	(22	)
Net income	140		134		140

Great Lakes

The Partnership, through its interest in TC GL Intermediate Limited Partnership owns a 46.45 percent general partner interest in Great Lakes. TransCanada owns the other 53.55 percent partnership interest. TC GL Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Great Lakes. The Partnership holds a 98.9899 percent limited partnership interest in TC GL Intermediate Limited Partnership.

Great Lakes operates under rates established pursuant to a settlement approved by FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2016, 2015, and 2014.

The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2016, respectively. These amounts represent the Partnership’s 46.45 percent share of a $9 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

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 have 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 and the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest 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.

The summarized financial information for Great Lakes is as follows:

December 31 (millions of dollars)	2016	2015

Assets
Current assets	66	86
Plant, property and equipment, net	714	727
	780	813

Liabilities and Partners’ Equity
Current liabilities	40	31
Long-term debt, net (a),(b)	278	297
Partners’ equity	462	485
	780	813

(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

(b) Includes current maturities of $19 million as of December 31, 2016 (December 31, 2015 - $19 million).

Year ended December 31 (millions of dollars)	2016		2015		2014

Transmission revenues	179		177		146
Operating expenses	(69	)	(59	)	(53	)
Depreciation	(28	)	(28	)	(28	)
Financial charges and other	(21	)	(23	)	(25	)
Net income	61		67		40

NOTE 5 PLANT, PROPERTY AND EQUIPMENT

The following table includes plant, property and equipment of our consolidated entities:

	2016 (a)				2015 (a)
December 31 (millions of dollars)	Cost	Accumulated Depreciation		Net Book Value	Cost	Accumulated Depreciation		Net Book Value
Pipeline	2,540	(879	)	1,661	2,535	(806	)	1,729
Compression	519	(148	)	371	516	(134	)	382
Metering and other	205	(61	)	144	201	(57	)	144
Construction in progress	4	—		4	2	—		2
	3,268	(1,088	)	2,180	3,254	(997	)	2,257

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

NOTE 6 ACQUISITIONS

2016 PNGTS Acquisition

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt.

The Partnership funded the cash portion of the transaction using proceeds received in 2015 from our ATM Program and additional borrowings under our Senior Credit Facility. The purchase agreement provides for additional payments to TransCanada ranging from $5 million up to a total of $50 million if pipeline capacity is expanded to various thresholds during the fifteen year period following the date of closing.

The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

The net purchase price was allocated as follows:

(millions of dollars)

Net Purchase Price (a)		193

Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016		120
Excess purchase price (b)		73

(a) Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

(b) The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

2015 GTN Acquisition

On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada (2015 GTN Acquisition), which resulted in GTN being wholly-owned by the Partnership. The total purchase price of the 2015 GTN Acquisition was $446 million plus the final purchase price adjustment of $11 million, for a total of $457 million. The purchase price consisted of $264 million in cash (including the final purchase price adjustment of $11 million), the assumption of $98 million in proportional GTN debt and the issuance of 1,900,000 new Class B units to TransCanada valued at $50 each, representing a limited partner interest in the Partnership with a total value of $95 million.

The Partnership funded the cash portion of the transaction using a portion of the proceeds received on our March 13, 2015 debt offering (refer to Note 7). The Class B units entitle TransCanada to a distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. Under the terms of the Third Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement), the Class B distribution was initially

NOTE 7 DEBT AND CREDIT FACILITIES

(millions of dollars)	December 31, 2016 (c)		Weighted Average Interest Rate for the Year Ended December 31, 2016 (c)		December 31, 2015 (c)	Weighted Average Interest Rate for the Year Ended December 31, 2015 (c)

TC PipeLines, LP
Senior Credit Facility due 2021	160		1.72	%	200	1.44	%
2013 Term Loan Facility due 2018	500		1.73	%	500	1.44	%
2015 Term Loan Facility due 2018	170		1.63	%	170	1.47	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(b)	350	4.375	%(b)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	65		1.43	%	75	1.15	%
PNGTS
5.90% Senior Secured Notes due December 2018	53		5.90	%(b)	69	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2019	10		1.64	%	—	—
3.82% Series D Senior Notes due 2017	12		3.82	%(b)	16	3.82	%(b)
	1,920				1,980
Less: unamortized debt issuance costs and debt discount (a)	9				9
Less: current portion	52	(d)			36
	1,859				1,935

(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

(b) Fixed interest rate.

(d) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017 (Refer to Note 24-Subsequent Events).

TC PipeLines, LP

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 (refer to Note 6) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

PNGTS

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.

GTN

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

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 principal repayments required by the Partnership on its consolidated debt are as follows:

(millions of dollars)

2017	52	(a)
2018	715	(a)
2019	43
2020	100
2021	510
Thereafter	500
	1,920	(a)

(a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).

NOTE 8 OTHER LIABILITIES

December 31 (millions of dollars)	2016	2015

Regulatory liabilities	25	24
Other liabilities	3	3
	28	27

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates and recognizes regulatory liabilities in this respect in the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations.

NOTE 9 PARTNERS’ EQUITY

At December 31, 2016, the Partnership had 67,454,831common units outstanding, of which 50,370,000 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada, including 5,797,106 common units held by our General Partner. Additionally, TransCanada, through our General Partner, owns 100 percent of our IDRs and an effective two percent general partner interest in the Partnership. TransCanada also holds 100 percent of our 1,900,000 outstanding Class B units.

ATM Equity Issuance Program (ATM Program)

In August 2014, the Partnership launched its $200 million ATM program pursuant to which, the Partnership may from time to time, offer and sell, through sales agents, common units, representing limited partner interests.

On August 5, 2016, the Partnership entered into a new $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Sales of the common units will be issued pursuant to the Partnership’s shelf registration statement on Form S-3 (Registration No. 333-211907), which was declared effective by the SEC on August 4, 2016.

In 2016, the Partnership issued 3.1 million common units under the ATM Program generating net proceeds of approximately $164 million, plus an additional $3 million from the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $2 million. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility for the 2016 PNGTS Acquisition and for general partnership purposes. The 3.1 million common units issued include the 1.6 million common units subject to rescission as discussed below.

In 2015, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $43 million, plus an additional $1 million from the General Partner’s to maintain its effective two

percent interest. The commissions to our sales agents were approximately $0.4 million. The net proceeds were used for general partnership purposes.

In 2014, the Partnership issued 1.3 million common units under the ATM Program generating net proceeds of approximately $71 million, plus an additional $2 million from the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $1 million. The net proceeds were used to finance the 2014 Bison Acquisition (refer to Note 6).

Common unit issuance subject to rescission

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program. However, we were advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities. If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions. If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions. The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

At December 31, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 2016 up to and including May 19, 2016, which may be subject to rescission rights, outside of equity given the potential redemption feature which is not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.

The total amount transferred outside of equity was approximately $83 million which includes interest, less distributions paid, and includes our General Partner’s share to maintain its effective two percent interest.

No unitholder claimed or attempted to exercise any rescission rights prior to the expiry dates of such rights and the final rights related to the sales of such units expired on May 19, 2017. Therefore, all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

Issuance of Class B units

On April 1, 2015, we issued Class B units to TransCanada to finance a portion of the 2015 GTN Acquisition. The Class B units entitle TransCanada to an annual distribution which is an amount based on 30 percent of cash distributions from GTN exceeding certain annual thresholds (refer to Note 6). The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation.

The Class B units’ equity account is increased by the excess of 30 percent of GTN’s distributions over the annual threshold until such amount is declared for distribution and paid every first quarter of the subsequent year.

For the year ended December 31, 2016 and 2015, the Class B units’ equity account was increased by $22 million and $12 million, respectively. These amounts equal 30 percent of GTN’s total distributable cash flow above the $20 million threshold in 2016 and $15 million in 2015 (refer to Notes 12 and 13).

NOTE 10 ACCUMULATED OTHER COMPREHENSIVE LOSS

The changes in accumulated other comprehensive loss (AOCL) by component are as follows:

	Cash flow hedges (a)
	(millions of dollars)
Balance at December 31, 2013	(5	)
Change in fair value of cash flow hedges	(1	)
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income (loss)	—
Balance at December 31, 2014	(5	)
Change in fair value of cash flow hedges	—
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	1
Balance at December 31, 2015	(4	)
Change in fair value of cash flow hedges	3
Amounts reclassified from AOCL	(2	)
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	2
Balance as of December 31, 2016	(2	)

(a) Recast to consolidate PNGTS for all periods presented (Refer to in Note 2). Additionally, AOCL as presented here is net of non-controlling interest on PNGTS.

NOTE 11 FINANCIAL CHARGES AND OTHER

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

Interest expense (b)	69		65		59
Net realized loss related to the interest rate swaps	3		2		2
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1		1		1
Other	(2	)	(5	)	(1	)
	71		63		61

(a) Recast to consolidate PNGTS for all periods presented.

(b) Effective January 1, 2016, interest expense includes amortization of debt issuance costs and discount costs. Refer to Note 3.

NOTE 12 NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit is computed by dividing net income attributable to controlling interests, after deduction of net income attributed to PNGTS’ former parent, amounts attributable to the General Partner andClass B units, by the weighted average number of common units outstanding.

The amounts allocable to the General Partner equals an amount based upon the General Partner’s effective two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement (refer to Note 13).

The amount allocable to the Class B units in 2016 equals an amount based upon 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million (2015 - $15 million).

Net income (loss) per common unit was determined as follows:

(millions of dollars, except per common unit amounts)	2016			2015			2014

Net income attributable to controlling interests (a)	248			37			195
Net income attributable to PNGTS’ former parent (a) (b)	(4		)	(24		)	(23		)
Net income allocable to General Partner and Limited Partners	244			13			172
Incentive distributions attributable to the General Partner (c)	(7		)	(3		)	(1		)
Net income attributable to the Class B units (d)	(22		)	(12		)	—
Net income (loss) allocable to the General Partner and common units	215			(2		)	171
Net income (loss) allocable to the General Partner’s two percent interest	(4		)	—			(3		)
Net income (loss) attributable to common units	211			(2		)	168
Weighted average common units outstanding (millions) — basic and diluted	65.7		(e)	63.9			62.7
Net income (loss) per common unit — basic and diluted (f)	$	3.21		$	(0.03	)	$	2.67

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

(b) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units or Class B units.

(c) Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

(d) As discussed in Note 9, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interests to the Class B units in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2016 less the threshold level of $20 million (2015 - less $15 million). During the year ended December 31, 2016, 30 percent of GTN’s total distributable cash flow was $42 million. As a result of exceeding the threshold level of $20 million, $22 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2016 (2015 - $12 million). Refer to Note 9.

(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 9.

(f) Net income (loss) per common unit prior to recast.

NOTE 13 CASH DISTRIBUTIONS

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on Available Cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner.

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution.

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 (refer to Note 24).

(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 (refer to Note 6 and 9).

(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.

(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 (refer to Note 9 and 24).

NOTE 14 CHANGE IN OPERATING WORKING CAPITAL

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

Change in accounts receivable and other	(4	)	6		2
Change in other current assets	(4	)	(1	)	(1	)
Change in accounts payable and accrued liabilities (a)	5		(2	)	29
Change in accounts payable to affiliates	—		(15	) (b)	(6	)
Change in state income taxes payable	—		(5	)	2
Change in accrued interest	2		(3	)	3
Change in operating working capital	(1	)	(20	)	29

(a) The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our cash flow statement during 2016.

(b) Excludes certain non-cash items primarily related to accruals of $10 million for construction of GTN’s Carty Lateral and $2 million of costs related to acquisition of 49.9 percent interest in PNGTS (Refer to Note 6).

NOTE 15 TRANSACTIONS WITH MAJOR CUSTOMERS

The following table shows revenues from the Partnership’s major customers comprising more than 10 percent of the Partnership’s total consolidated recasted revenues (refer to Note 2) for the years ended December 31, 2016, 2015 and 2014:

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

Anadarko Energy Services Company (Anadarko)	48		48	48
Pacific Gas and Electric Company (Pacific Gas)	36	(a)	42	45

At December 31, 2016 and 2015, Anadarko owed the Partnership approximately $4 million, which is approximately 10 percent of our consolidated recasted trade accounts receivable (Refer to Note 2).

(a) Less than 10 percent

NOTE 16 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $3 million for each of the years ended December 31, 2016, 2015 and 2014.

As operator, TransCanada’s subsidiaries provide capital and operating services to GTN, Northern Border, PNGTS, Bison, Great Lakes, North Baja and Tuscarora (together, “our pipeline systems”). TransCanada’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs.

Capital and operating costs charged to our pipeline systems for the years ended December 31, 2016, 2015 and 2014 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at December 31, 2016 and 2015 are summarized in the following tables:

Year ended December 31 (millions of dollars)	2016	2015	2014

Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	30	30	30
Northern Border (a)	32	36	35
PNGTS (a) (b)	8	8	8
GTN (a) (c)	27	30	30
Bison (a) (d)	2	4	6
North Baja	4	5	5
Tuscarora	5	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	13	13	13
Northern Border	12	14	16
PNGTS (b)	5	5	5
GTN (c)	24	25	19
Bison (d)	3	4	4
North Baja	4	5	4
Tuscarora	4	4	4

December 31 (millions of dollars)	2016	2015
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	4	3
Northern Border (a)	4	5
PNGTS (a) (b)	1	3
GTN	3	3
Bison	1	—
North Baja	1	—
Tuscarora	1	1

(a) Represents 100 percent of the costs.

(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

(d) In 2014, the Partnership acquired the remaining 30 percent interest in Bison (Refer to Note 6).

Great Lakes

Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the year ended December 31, 2016, Great Lakes earned 68 percent of its transportation revenues from TransCanada and its affiliates (2015 — 71 percent; 2014 — 49 percent). Additionally, Great Lakes earned approximately one percent of its total revenues as affiliated rental revenue in 2016 (2015 — 1 percent and 2014 — 1 percent).

At December 31, 2016, $19 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 — $17 million).

Great Lakes operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its shippers certain percentages of any qualifying revenues earned above a certain ROEs. A refund of $2.5 million was paid to shippers in 2016 relating to the year ended December 31, 2015, of which approximately 85 percent was made to affiliates of Great Lakes. For the year ended December 31, 2016, Great Lakes has recorded an estimated revenue sharing provision amounting to $7.2 million and Great Lakes expects that a significant percentage of the refund will be to its affiliates as well.

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.

Effective November 1, 2014, Great Lakes executed contracts with an affiliate, ANR Pipeline Company (ANR), to provide firm service in Michigan and Wisconsin. These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts. On December 3, 2014, FERC accepted and suspended Great Lakes’ tariff records to become effective May 3, 2015, subject to refund. On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by Great Lakes, which allowed additional time for FERC to consider Great Lakes’ request. Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filed a settlement with FERC that included an agreement by ANR to pay Great Lakes the difference between the historical and maximum rates (ANR Settlement). Great Lakes provided service to ANR under multiple service agreements and rates through May 3, 2015 when Great Lakes’ tariff records became effective and subject to refund. Great Lakes deferred an approximate $9 million of revenue related to services performed in 2014 and approximately $14 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement. As a result, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015.

PNGTS

For the years ended December 31, 2016 and 2015, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2016 and 2015 were approximately $2 million and $3 million, respectively. At December 31, 2016, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

NOTE 17 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2016 and 2015:

Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30		Dec 31
2016
Transmission revenues (a)	111		101		103		111
Equity earnings (a) (b ) (c)	33		20		22		22
Net income (a)	81		57		60		65
Net income attributable to controlling interests (a)	74		55		58		61
Net income per common unit (d)	$	1.10	$	0.76	$	0.65	$	0.70
Cash distribution paid (f)	71		60		65		66
2015
Transmission revenues (a)	114		97		96		110
Equity earnings (e)	31		15		17		34
Impairment of equity-method investment (b)	—		—		—		(199		)
Net income (loss) (a)	81		47		54		(124		)
Net income (loss) attributable to controlling interests (a)	67		46		52		(128		)
Net income (loss) per common unit (d)	$	0.88	$	0.66	$	0.70	$	(2.27	)
Cash distribution paid (f)	55		55		59		59

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on equity method goodwill included as part of the carrying value of our equity investments.

(c) During the year ended December 31, 2016, no impairment has been identified related to our equity investments in Northern Border and Great Lakes.

(d) Historical net income (loss) per common unit was not recasted.

(e) During the three months ended December 31, 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. During the year ended December 31, 2015, no impairment has been identified on our investment in Northern Border (Refer to Note 4).

(f) Distributions paid to common units and Class B units.

NOTE 18 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

· Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

· Level 3 inputs are unobservable inputs for the asset or liability.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

(b) Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, accounts payable to affiliates, accrued interest and short-term debt approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. 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 fair value of interest rate derivatives is calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model.

The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance.

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at December 31, 2016 and December 31, 2015 was $1,963 million and $1,945 million, respectively.

The ATM common units which may be subject to rescission rights, as discussed more fully in Note 9, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

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). Refer to Note 11 — Financial Charges and Other.

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 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.

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 cash and cash equivalents and receivables, 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 December 31, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2016, we had a credit risk concentration on one of our customers and the amount owed is greater than 10 percent of our recasted trade accounts receivable (refer to Note 15).

(c) Other

The estimated fair value measurements on Tuscarora (refer to Note 20) and our equity investment in Great Lakes (refer to Note 4) are both classified as Level 3. In the determination of the fair value, we used internal forecasts on expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates as discussed more fully on Notes 4 and 20.

NOTE 19 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2016 (a)	2015(a)

Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	1	—
	47	41

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

NOTE 20 GOODWILL AND REGULATORY

Tuscarora - On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 22, 2016, Tuscarora filed a petition with FERC requesting appeal of the Stipulation and Agreement of Settlement (Tuscarora Settlement) Tuscarora made with its customers. On September 22, 2016, FERC approved the Tuscarora Settlement that resolved the Section 5 rate review initiated by FERC in January 2016. 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 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.

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.

North Baja —On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. The requested abandonments will not have any impact on existing firm transportation service.

GTN — GTN operates under rates established pursuant to a settlement approved by FERC in June 2015. Beginning in January 2016, GTN’s rates decreased by 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates.

PNGTS - PNGTS continues to operate under the rates approved by FERC in February 2015 (Refer to Note 2-Significant Accounting Policies-Revenue Recognition). PNGTS has no requirement to file a new rate proceeding.

NOTE 21 CONTINGENCIES

The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the 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. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements.

Below are the material legal proceedings that might have a significant impact on the Partnership:

Great Lakes v. Essar Steel Minnesota LLC, et al. — On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. In July 2016, Essar Minnesota filed for Bankruptcy. The Foreign Essar Affiliates have not filed for bankruptcy. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Great Lakes currently is proceeding against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April, after reaching agreement with creditors on an allowed claim, the Bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million.

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. — On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant. The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units. Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees. The Partnership has moved to dismiss the complaint and intends to defend vigorously against the claims asserted. In April 2016, the Chancery Court granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint. The plaintiff has appealed the decision to dismiss its claims. The appeal of this matter was heard by the Delaware Supreme Court in December, 2016. The court found in TransCanada’s favor and dismissed the Plaintiff’s motion. There are no further rights of appeal.

NOTE 22 VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.

Consolidated VIEs

The Partnership’s consolidated VIEs consist of the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability that it absorbs from the ILPs’ economic performance.

The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes and PNGTS due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s Consolidated Balance Sheets:

(millions of dollars)	December 31, 2016(b)		December 31, 2015(b)

ASSETS (LIABILITIES) (a)
Cash and cash equivalents	14		16
Accounts receivable and other	33		29
Inventories	6		6
Other current assets	6		6
Equity investments	918		965
Plant, property and equipment	1,146		1,180
Other assets	2		2
Accounts payable and accrued liabilities	(21	)	(27	)
Accounts payable to affiliates, net	(32	)	(9	)
Distributions payable	(3	)	(10	)
Accrued interest	(2	)	(1	)
Current portion of long-term debt	(52	)	(36	)
Long-term debt	(337	)	(373	)
Other liabilities	(25	)	(24	)
Deferred state income tax	(10	)	(11	)

(a) North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.

(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

NOTE 23 INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2016, 2015 and 2014 relate primarily to utility plant. For the years ended December 31, 2016, 2015 and 2014, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

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

State income taxes
Current	1	(2	)	3
Deferred	—	4		(1	)
	1	2		2

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

NOTE 24 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 2017, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

Partnership

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 and was paid on February 14, 2017 to unitholders of record as of February 2, 2017. The declared distribution totaled $68 million and was paid in the following manner: $64 million to common unitholders (including $5 million to the General Partner as holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $4 million to our General Partner, which included $2 million for its effective two percent general partner interest and $2 million of IDRs payment.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million and 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 $20 million.

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 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 acquisition.The indenture for the notes contains customary investment grade covenants.

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 (refer to Note 5) 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 acquisition of a 49.34 percent interest in Iroquois was accounted prospectively and as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

The acquisition of an additional 11.81 percent interest in PNGTS, which resulted to the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS was recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.

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.

Northern Border

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

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.

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.

PNGTS

On January 3, 2017, PNGTS paid the amount due on December 31, 2016 on its 2003 Senior Secured Notes amounting to $6.3 million representing $5.5 million in principal and $0.8 million in interest pursuant to the terms of the Note Purchase agreement. Under the agreement, any principal and interest that is due on a date other than a normal business day shall be made on the next succeeding business day without additional interest or penalty.

(millions of dollars)

Net Purchase Price (a)		359

Less: TransCanada’s carrying value of non-controlling interest at April 1, 2015		232
Excess purchase price (b)		127

(millions of dollars)
Total cash consideration		217
TransCanada’s carrying value of non-controlling interest at October 1, 2014		188
Excess purchase price		29