We believe our strong financial position, including available unused capacity on our credit facility, gives us the capacity to pursue opportunities to grow in a sustained and disciplined manner for the long-term benefit of our unitholders.

 

FACTORS THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS

 

Our pipeline systems provide natural gas transportation services to their customers. The majority of these services are provided through firm service transportation contracts with a reservation charge to reserve pipeline capacity, regardless of use, for the term of the contract. The revenues associated with capacity under firm service transportation contracts are not subject to fluctuations caused by changing supply and demand conditions, competition, and customers for the term of the contract.

 

 

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The following table provides information with respect to the proportion of capacity subscribed under firm contracts and their weighted average remaining contract life as at April 1, 2010 for our pipeline systems.

 

		As at April 1, 2010
	Our Ownership Interest	Firm Contracted Capacity %(a)	Weighted Average Remaining Contract Life (in Years)(c)
Great Lakes	46.45%	87%	1.9
Northern Border	50%	75%	2.4
North Baja	100%	(b) 79% southbound 64% northbound	16.5
Tuscarora	100%	97%	10.4

 

(a)Firm contracted capacity is calculated based upon contracted capacity compared to design capacity for Great Lakes and Northern Border, North Baja northbound transportation and Tuscarora, and compared to FERC licensed capacity for North Baja southbound transportation.

(b)Due to North Baja's bi-directional nature, it can contract for both southbound and northbound capacity separately and concurrently.

(c)Weighted average remaining contract life is weighted based upon maximum daily quantity in the contracts.

 

Key factors that impact the business of our pipeline systems are the level of capacity under firm contracts and related term, supply of and demand for natural gas in the markets in which our pipeline systems operate, competition, and customers and the mix of services they require. Government regulation of natural gas pipelines is also a major factor impacting the business of our pipeline systems. These factors are discussed in more detail below.

 

When there is capacity that is not contracted under firm service transportation contracts, there is exposure to fluctuations in earnings caused by changes in certain of the key factors key factors discussed above. Our North Baja and Tuscarora pipeline systems have little risk of fluctuations in revenues as a result of their strong contracted capacity position under long-term contracts.

 

Government regulation of natural gas pipelines includes, among others, regulation of the terms of and rates for interstate natural gas transportation services, environmental issues, and pipeline safety and integrity.

 

Natural Gas Supply and Demand

 

The ongoing impacts of decreased demand for natural gas in North America related to the economic environment, increased production from U.S. shale gas developments and high levels of natural gas in storage continued to hold commodity prices for natural gas at low levels over the first quarter as compared to the first quarter of 2009. We expect these pressures on natural gas commodity prices to continue through the remainder of 2010.

 

The primary source of natural gas transported by our pipeline systems, excluding North Baja, is the WCSB. “Gas exiting the WCSB” is the term we use to represent the net of the supply of and demand for natural gas in the WCSB region.  It is dependent upon WCSB natural gas production levels, demand for natural gas in Western Canada, and natural gas storage capacity and demand for natural gas storage injection in Western Canada. Gas exiting the WCSB was lower in the first quarter of 2010 compared to the same period in 2009, due mainly to decreased production. Lower WCSB production is expected to continue through the remainder of 2010 as a result of a decline in drilling and exploration activity for natural gas in the basin over the last two years, mainly due to lower natural gas prices.

 

 

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Factors which may support increased WCSB production in the future include strengthening gas prices and reduced royalty costs, which would support exploration and development of new fields in Western Canada by WCSB natural gas producers. Drilling in the WCSB is expected to recover in the future when gas prices stabilize and exploration and development costs become more economical through factors such as more efficient and productive drilling. Over the long term, we expect WCSB natural gas producers will direct significant resources toward development of unconventional resources such as shale gas and coalbed methane. Additional natural gas supply from the Alberta Hub is expected to be available in the future when new pipeline projects associated with the Montney and Horn River shale gas regions in Western Canada are constructed, or if the l onger term potential associated with the proposed development of the Mackenzie Delta in Northern Canada and the North Slope in Alaska is realized.

 

Levels of Western Canadian natural gas in storage and U.S. working gas storage levels at the end of the first quarter of 2010 continued to be at the record highs experienced throughout 2009. The winter season is usually a period of withdrawals from storage.  However, there were lower storage withdrawals in Western Canada in the first quarter of 2010 relative to the same period in 2009, which contributed to reduced volumes of gas exiting the WCSB. Weather related demand in the first quarter of 2010 did not result in sufficient storage withdrawals in the U.S. market storage areas to offset the high levels of natural gas in storage at the beginning of the winter heating season.  The high demand period for storage injection usually begins in the spring and extends through most of the summer. However, high levels of natural gas already in storage in the market regions are expected to reduce demand for transportation services related to storage injection during the remainder of 2010. High overall storage levels have a dampening effect on natural gas prices, which in turn contributes to reduced production.

 

Continued strengthening of the North American economy and decreased natural gas inventories resulting from reduced production levels and seasonal weather related demand are factors that would positively affect natural gas prices in the near term.

 

North America’s demand for natural gas is expected to rise as the economy returns to growth mode. The relative environmental merits of natural gas versus other carbon based forms of energy are also expected to increase the demand for natural gas in the future.

 

U.S. natural gas production slightly increased over the last two quarters, mainly due to the enhanced productivity of new wells being drilled to develop unconventional resources in the lower 48 states. Production from natural gas basins other than the WCSB represents supply competition for WCSB natural gas. Overall, U.S. natural gas production is expected to decrease somewhat for the 2010 year as a whole compared to recent years. Production from individual natural gas basins in North America will depend on factors that include natural gas drilling activity, well production rates, and relative operating costs. Reduced natural gas drilling activity in North America as a whole is expected to contribute to lower production overall.

 

Demand for Transportation Services and Contracting

 

Demand for natural gas transportation service on our pipeline systems is directly related to the activity in the natural gas markets served by these systems. Factors that may impact demand for transportation service on any one system include the availability of natural gas supply at the pipeline system’s receipt points, the ability and willingness of natural gas shippers to utilize that system over alternative pipelines, relative transportation rates, and the volume of natural gas delivered to markets supplied by that system from other supply sources and storage facilities. The impact of changes in demand for natural gas transportation services on operating revenues for our pipeline systems is dependent upon the extent to which capacity has been contracted under long-term firm contracts. Contracted capacity and system throughput are measures of demand for natural gas transportation services.

 

The reduced level of gas exiting the WCSB has resulted in excess pipeline capacity serving the WCSB. We anticipate there will be excess natural gas pipeline capacity serving the WCSB for the foreseeable future and therefore competition for gas exiting the WCSB will continue. In this environment, there is little incentive for shippers to make long-term commitments for capacity and the trend towards shorter term contracts is expected to continue for Great Lakes and Northern Border. As a result, there may be increased volatility and seasonality with respect to throughput and revenues for these pipelines.

 

 

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Prevailing market conditions and dynamic competitive factors in North America, particularly reduced gas exiting the WCSB, increased supply from other supply basins to our pipeline systems’ market areas, and the economic environment affecting the demand for natural gas, have reduced the value of transportation on our pipeline systems and their ability to market available capacity.  We expect the downward pressure on transportation values for our pipeline systems to continue through 2010.

 

Great Lakes

 

Great Lakes’ average contracted capacity was 94 per cent of its average design capacity for the first quarter of 2010, compared to 100 per cent in the first quarter of 2009. As at April 1, 2010, 87 per cent of its average design capacity was contracted on a firm basis with a weighted average remaining contract life of 1.9 years. In the absence of new contracting, beginning November 1, 2010, Great Lakes will have additional long haul capacity available of 440 thousand dekatherms per day (MDth/d) as a result of contract expiries, which will result in the average design capacity contracted on a firm basis decreasing to 67 per cent. Great Lakes’ revenue may decline from November 1, 2010 onward if it is required to discount rates to recontract or is unable to recontract its expiring capacity.

 

Scheduled throughput on Great Lakes’ pipeline system for the first quarter of 2010 decreased to 2,133 MMcf/d compared to 2,549 MMcf/d for the same period in 2009 primarily due to underutilization of long-term firm contracts related to reduced gas exiting WCSB, along with warm weather in the market area which reduced transportation related to storage withdrawals and reduced demand for short-term transportation services due to substantial reductions in transportation values. Decreases in throughput related to underutilization of long-term firm contracts have a minimal impact on revenue earned from these contracts. When the level of long-term firm contracts decreases beginning in November 2010, Great Lakes may experience increased volatility in revenues as a result of changes in throughput.

 

Reduced demand for short-term services resulted in greater levels of discounting in the first quarter of 2010.  Great Lakes is expected to continue discounting short-term transportation capacity as needed to optimize revenue. Lower sales of short-term contracts and increased discounting reduce revenues earned from sales of short-term transportation services.

 

Northern Border

 

Northern Border’s average contracted capacity was 63 per cent of its design capacity for the first quarter of 2010, compared to 82 per cent for the first quarter of 2009. Competition for supply from the WCSB and increased deliveries of natural gas to Midwest markets from other supply sources continue to impact Northern Border’s ability to contract available capacity. These supply and demand factors are expected to maintain competitive pressures in the Midwest markets on WCSB sourced natural gas, as discussed further under “Competition.”  Northern Border was negatively impacted in the first quarter of 2010 by the incremental supply in the Chicago market from new infrastructure that went into service in 2009, as low transportation values on the eastern leg of the Northern Border system into Chicago resulted in s hippers with capacity on that portion of the system electing to deliver to an upstream delivery location which negatively impacts Northern Border’s ability to contract upstream capacity.  Scheduled throughput on Northern Border’s pipeline system in the first quarter of 2010 was 2,209 MMcf/d compared to 2,181 MMcf/d in the first quarter of 2009.  The slight incremental scheduled throughput in the first quarter of 2010 relative to the same period in 2009 was primarily due to increased short haul transportation services which have lower transportation rates than long haul transportation services.  As well, Northern Border continued to discount transportation capacity in the first quarter of 2010.  Northern Border expects to continue discounting available transportation capacity as needed to optimize revenue. As at April 1, 2010, Northern Border had approximately 75 per cent of its design capacity contracted, decreasing to approximately 50 per cent by the end o f the second quarter.  The weighted average remaining life of Northern Border’s contracts at April 1, 2010 was 2.4 years.

 

TransCanada’s Bison Pipeline will extend from the Powder River Basin producing region in Wyoming to an interconnection with the Northern Border system in Morton County, North Dakota. TransCanada expects the project to be placed into service in the fourth quarter of 2010. When completed, this project will increase Northern Border’s supply diversity as the interconnection will provide access to a new competitively-priced natural gas supply source for Northern Border’s shippers.  Over the long term, this should enhance utilization of Northern Border’s pipeline system.  Shippers on the Bison Pipeline have executed 10 year contracts for approximately 407 MMcf/d of capacity on the Northern Border system from Port of Morgan, Montana to Ventura, Iowa, commencing on the in-service date of the Bison Pipel ine. When the Bison Pipeline is completed, this would increase Northern Border’s average contracted capacity and weighted average contract life.  We expect that some or all of the volumes from the Bison Pipeline may displace existing shipments from the WCSB.  As such, any impact to Northern Border’s revenues will be dependent upon the overall demand for transportation to the markets served by Northern Border.

 

 

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Competition

 

There is currently increased competition among natural gas pipelines for gas exiting the WCSB due to excess pipeline capacity. Factors impacting the competition for gas exiting the WCSB include levels of firm transportation contracts on each pipeline, demand for natural gas in the regions served by each pipeline, and relative transportation values on each pipeline which are impacted by their transportation rates. Currently, factors impacting the competition for gas exiting the WCSB include high natural gas storage levels in Eastern Canada, Michigan and California, and as well as changes in basis differential for each of the pipelines accessing the WCSB resulting from new pipeline infrastructure recently placed into service.

 

Our pipeline systems compete primarily with other interstate and intrastate pipelines in the transportation of natural gas. Competition among natural gas pipelines is based primarily on transportation charges and proximity to natural gas supply areas and markets. New natural gas supplies from unconventional sources, such as shale, and new pipeline projects in the U.S. moving additional natural gas supply from the Rockies basin and from the Mid-Continent Shales have increased the supply competition in the markets served by our pipeline systems. This additional supply delivered to Midwest and Eastern markets is displacing traditional supply in the markets served by our pipeline systems.  Supply competition from other natural gas sources has impacted demand for transportation on our pipeline systems. As well, growth in supplies ava ilable from other natural gas producing regions has impacted prices for natural gas delivered to some of the markets our pipeline systems serve relative to other market regions. Increased competition within the North American natural gas industry has resulted in a trend towards shorter term contracting as customers assess and choose the markets which optimize their netback prices.

 

Supply competition in the Midwest markets from the Rockies Express Pipeline, along with deliveries from other supply sources via interconnecting pipelines continued to negatively impact demand for Northern Border’s transportation services in the first quarter of 2010, which resulted in increased discounting of sales of available capacity. The supply competition in the Midwest markets is expected to continue to impact demand for Northern Border’s transportation services through the remainder of 2010.

 

Government Regulation

 

Federal Energy Regulatory Commission – Natural gas transportation is regulated by the FERC and other federal and state regulatory agencies, including the Department of Transportation. FERC regulatory policies govern the rates that pipelines are permitted to charge customers for interstate transportation of natural gas. The operation and maintenance of our pipeline systems are also regulated by the federal and state regulatory agencies.

 

The FERC-approved rate designs used by our pipeline systems are based upon firm and interruptible services. Customers with firm service transportation agreements pay a fee known as a reservation charge to reserve pipeline capacity, regardless of use, for the term of their contracts. Firm service transportation customers may also pay a variable fee that is based on the distance and volume of natural gas they transport. Customers with interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service transportation requests are satisfied. Interruptible service customers are assessed a variable fee based on distance and volume of natural gas they transport. The majority of our pipeline systems’ revenue is generated from firm service transportation agreements.

 

Great Lakes Rate Proceeding – On November 19, 2009, the FERC issued an order in FERC Docket No. RP10-149 (November 2009 Order) instituting an investigation pursuant to Section 5 of the NGA (GL Rate Proceeding). The FERC alleged, based on a review of certain historical information, that Great Lakes’ revenues might substantially exceed Great Lakes’ actual cost of service and therefore may be unjust and unreasonable. On February 4, 2010, Great Lakes filed a cost and revenue study (GL Cost and Revenue Study) in response to the November 2009 Order. The GL Cost and Revenue Study reflects the increased risk of de-contracting on the Great Lakes system which may result in decreases to overall long-term, daily and short-term firm transportation revenues, and interruptible transportation reve nues, as compared to prior periods.

 

 

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On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) indicating that an agreement in principle has been reached among Great Lakes, active participants and the FERC trial staff.  The Motion requests a temporary suspension of the GL Rate Proceeding schedule for all parties to permit the drafting of a stipulation and agreement, and the Motion was granted by the Chief Administrative Law Judge on the same day.  The parties are negotiating the settlement terms and anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC.  Until the filing of the written stipulation and agreement, the terms of a settlement will remain confidential.   ;In the absence of a settlement, a hearing in the GL Rate Proceeding is scheduled for early August 2010 and an initial decision by the Administrative Law Judge is expected in November 2010.   Any of the following elements of Great Lakes’ rate structure may be affected in settlement or litigation, including but not limited to: firm transportation, interruptible transportation and/or incremental rates; revenues; depreciation; and interruptible transportation revenue sharing.  A revised rate structure as a result of a settlement, if reached, would be in place as early as the second quarter of 2010.

 

We currently do not expect that the rate case settlement, if reached, will have a material effect on Great Lakes’ revenues in the context of the current market environment.  See the Great Lakes discussion under “Demand for Transportation Services and Contracting” in this section.  However, the ultimate impact on revenues will remain confidential until the stipulation and agreement is approved by the Administrative Law Judge and the FERC.

 

Air Emissions – The Clean Air Act (CAA) and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements.

 

By letter dated December 28, 2009, the EPA required Great Lakes to provide information regarding its natural gas compressor stations in the states of Minnesota, Wisconsin and Michigan as part of the EPA’s review of Great Lakes’ compliance with the CAA. Great Lakes is in the process of preparing its response and providing the information, all of which is due by May 29, 2010. Any issues that may arise as a result of this information request are not determinable at this time.

 

On February 2, 2009, Northern Border received a Notice of Violation (NOV) from the EPA alleging that Northern Border was in violation of certain regulations pursuant to the CAA regarding a compressor station on its system. On April 1, 2010, Northern Border received indication from the EPA that it does not intend to file a complaint against Northern Border with respect to the NOV.  Northern Border expects no further action from the EPA regarding this NOV.

 

HOW WE EVALUATE OUR OPERATIONS

 

We evaluate our business primarily on the basis of the underlying operating results for each of our pipeline systems, along with a measure of Partnership cash flows. This measure does not have any standardized meaning prescribed by U.S. generally accepted accounting principles (GAAP). It is, therefore, considered to be a non-GAAP measure and is unlikely to be comparable to similar measures presented by other entities. Partnership cash flows include cash distributions from the Partnership’s equity investments, Great Lakes and Northern Border, plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja (post-acquisition) and Tuscarora, net of Partnership costs and distributions declared to the general partner. 

 

RESULTS OF OPERATIONS OF TC PIPELINES, LP

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting policies and estimates during the three months ended March 31, 2010.

 

 

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Information about our critical accounting estimates is included under Item 7. “Management Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report on Form 10-K for the year ended December 31, 2009.

 

NET INCOME

 

The Partnership uses the non-GAAP financial measure “Net income prior to recast” as a financial performance measure. Net income prior to recast excludes North Baja’s net income for periods prior to July 1, 2009, the date on which the Partnership acquired North Baja. The acquisition of North Baja from TransCanada was accounted for as a transaction under common control, similar to a pooling of interests, whereby the Partnership’s historical financial information was recast to include the net income of North Baja for all periods presented, which included income that did not accrue to the Partnership’s general partner interest or to the Partnership’s common units, but rather accrued to North Baja’s former parent.

 

Net income prior to recast is presented to enhance investors’ understanding of the way management analyzes the Partnership’s financial performance. Net income prior to recast is provided as a supplement to GAAP financial results and is not meant to be considered in isolation or as a substitute for financial results prepared in accordance with GAAP.

 

To supplement our financial statements, we have presented a comparison of the earnings contribution components from each of our investments. We have presented net income in this format to enhance investors’ understanding of the way management analyzes our financial performance. We believe this summary provides a more meaningful comparison of our net income to prior years, as we account for our partially-owned pipeline systems using the equity method. The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

 

The shaded areas in the tables below disclose the results from Great Lakes and Northern Border, representing 100 per cent of each entity's operations for the given period.
		For the three months ended March 31, 2010																				For the three months ended March 31, 2009
(unaudited) (millions of dollars)		PipeLP				Other Pipes(a)				Corp(b)				GLGT			NBPC(c)					PipeLP				Other Pipes(a)				Corp(b)				GLGT			NBPC(c)
Transmission revenues			17.4				17.4				-				72.9				69.1				8.4				8.4				-			82.5			74.5
Operating expenses			(3.4	)			(3.4	)			-				(14.2	)			(18.0	)			(1.4	)			(1.4	)			-			(16.0		)	(18.5			)
General and administrative			(1.3	)			-				(1.3	)			-		-						(1.2	)			-				(1.2	)		-			-
			12.7				14.0				(1.3	)			58.7		51.1						5.8				7.0				(1.2	)		66.5			56.0
Depreciation			(3.7	)			(3.7	)			-				(14.3	)	(15.4			)			(1.8	)			(1.8	)			-			(14.6		)	(15.3			)
Financial charges, net and other			(6.2	)			(1.0	)			(5.2	)			(7.9	)	(6.0			)			(7.3	)			(1.1	)			(6.2	)		(8.2		)	(9.1			)
Michigan business tax			-				-				-				(1.5	)	-						-				-				-			(1.8		)	-
															35.0				29.7															41.9			31.6
Equity income			30.9				-				-				16.3				14.6				35.1				-				-				19.5				15.6
Net income prior to recast			33.7				9.3				(6.5	)			16.3				14.6				31.8				4.1				(7.4	)			19.5				15.6
North Baja's contribution prior to acquisition(d)			-				-				-				-				-				4.1				4.1				-				-				-
Net income(d)			33.7				9.3				(6.5	)			16.3				14.6				35.9				8.2				(7.4	)			19.5				15.6

 

(a) “Other Pipes” includes the results of North Baja and Tuscarora.

 

(b) “Corp” includes the costs of the Partnership, but excludes the costs of its subsidiaries.

 

(c) The Partnership owns a 50 per cent general partner interest in Northern Border. Equity income from Northern Border includes the 12-year amortization of a $10.0 million transaction fee paid to the operator of Northern Border at the time of the additional 20 per cent acquisition in April 2006.

 

(d) The acquisition of North Baja from TransCanada was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of North Baja were recorded at TransCanada's carrying value and the Partnership’s historical financial information was recast to include North Baja for all periods presented on a consolidated basis.

 

 

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First Quarter 2010 Compared with First Quarter 2009

Net income decreased $2.2 million to $33.7 million in the first quarter of 2010 compared to $35.9 million in the first quarter of 2009. Excluding the contribution from North Baja prior to the acquisition, net income prior to recast increased $1.9 million to $33.7 million in the first quarter of 2010 compared to $31.8 million in first quarter of 2009. This increase was primarily due to net income of $5.4 million from North Baja which was partially offset by lower equity income from Great Lakes and Northern Border.

 

Equity income from Great Lakes was $16.3 million in the first quarter of 2010, a decrease of $3.2 million compared to $19.5 million in the first quarter of 2009. The decrease in equity income was primarily due to decreased transmission revenues. Great Lakes’ transmission revenues for the three months ended March 31, 2010 decreased $9.6 million compared to the same period last year, primarily due to decreased demand for short-term transportation services.  Operating expenses decreased $1.8 million primarily due to lower pipeline maintenance and overhaul costs and lower property taxes.

 

Equity income from Northern Border was $14.6 million in the first quarter 2010, a decrease of $1.0 million compared to the same period in 2009. The decrease in equity income was primarily due to decreased transmission revenues partially offset by reduced financial charges.  Northern Border’s transmission revenues decreased $5.4 million due to increased discounting of transportation rates for volumes transported.  Financial charges, net and other decreased $3.1 million in first quarter of 2010 compared to the same period in 2009 primarily due to lower effective interest rates and average debt outstanding.

 

Net income from Other Pipes, which includes results from North Baja and Tuscarora, was $9.3 million in the first quarter of 2010, an increase of $1.1 million compared to the first quarter of 2009. Excluding the contribution of $4.1 million from North Baja prior to the acquisition, net income from Other Pipes increased $5.2 million in the first quarter 2010. This increase was primarily due to North Baja, which contributed $5.4 million to net income in the first quarter of 2010.

 

Costs at the Partnership level were $6.5 million in the first quarter of 2010, a decrease of $0.9 million compared to the same period in 2009. This decrease was primarily due to lower financial charges, net and other as a result of lower effective interest rates.

 

PARTNERSHIP CASH FLOWS

 

The Partnership uses the non-GAAP financial measures “Partnership cash flows” and “Partnership cash flows before general partner distributions” as they provide measures of cash generated during the period to evaluate our cash distribution capability. As well, management uses these measures as a basis for recommendations to our general partner’s board of directors regarding the distribution to be declared each quarter. Partnership cash flow information is presented to enhance investors’ understanding of the way that management analyzes the Partnership’s financial performance.

 

Partnership cash flows include cash distributions from the Partnership’s equity investments, Great Lakes and Northern Border, plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja (post-acquisition) and Tuscarora, net of Partnership costs and distributions declared to the general partner. 

 

Partnership cash flows and Partnership cash flows before general partner distributions are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP.

 

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Non-GAAP Measures

Reconciliations of Net Income to Net Income Prior to Recast and Partnership Cash Flows

 

(unaudited)		Three months ended March 31,
(millions of dollars except per common unit amounts)		2010				2009
Net income(a)			33.7				35.9
North Baja's contribution prior to acquisition(a)			-				(4.1	)
Net income prior to recast			33.7				31.8
Add:
Cash distributions from Great Lakes(b)			15.7				12.5
Cash distributions from Northern Border(b)			16.4				24.2
Cash flows provided by North Baja's operating activities			4.7				-
Cash flows provided by Tuscarora's operating activities			7.2				7.2
			44.0				43.9
Less:
Equity income from investment in Great Lakes			(16.3	)			(19.5	)
Equity income from investment in Northern Border			(14.6	)			(15.6	)
North Baja's net income			(5.4	)			-
Tuscarora's net income			(3.9	)			(4.1	)
			(40.2	)			(39.2	)
Partnership cash flows before general partner distributions			37.5				36.5
General partner distributions(c)			(0.7	)			(3.2	)
Partnership cash flows			36.8				33.3
Cash distributions declared			(34.4	)			(27.7	)
Cash distributions declared per common unit(d)		$	0.730			$	0.705
Cash distributions paid			(34.4	)			(27.7	)
Cash distributions paid per common unit(d)		$	0.730			$	0.705

 

(a) The acquisition of North Baja from TransCanada was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of North Baja were recorded at TransCanada’s carrying value and the Partnership’s historical financial information was recast to include North Baja for all periods presented on a consolidated basis.

 

(b) In accordance with the cash distribution policies of the respective pipeline systems, cash distributions from Great Lakes and Northern Border are based on their respective prior quarter financial results.

 

(c) General partner distributions represent the cash distributions declared to the general partner with respect to its two per cent interest plus an amount equal to incentive distributions.

 

(d) Cash distributions declared per common unit and cash distributions paid per common unit are computed by dividing cash distributions, after the deduction of the general partner's allocation, by the number of common units outstanding. The general partner's allocation is computed based upon the general partner's two per cent interest plus an amount equal to incentive distributions.

 

 

First Quarter 2010 Compared with First Quarter 2009

Partnership cash flows increased $3.5 million to $36.8 million in the first quarter of 2010 compared to $33.3 million in same period of 2009. This increase was primarily due to $4.7 million of cash flows provided by North Baja’s operating activities in the first quarter of 2010, an increase of $3.2 million in cash distributions from Great Lakes, a decrease of $2.7 million in general partner distributions resulting from the restructuring of incentive distribution rights on July 1, 2009, and reduced Partnership financial charges of $0.9 million. These positive factors were partially offset by decreased cash distributions from Northern Border of $7.8 million.

 

 

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The Partnership paid distributions of $34.4 million in the first quarter of 2010, an increase of $6.7 million compared to 2009, due to an increase in the number of common units outstanding, in addition to increases in quarterly per common unit distribution amounts.

 

Other Cash Flows

On March 5, 2010, we acquired the Yuma Lateral expansion facilities and contracts in place at that time for a purchase price of $7.6 million.  The Yuma Lateral was placed into service on March 13, 2010.

 

 

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP

 

Overview

 

Our principal sources of liquidity include distributions received from our investments in Great Lakes and Northern Border, operating cash flows from North Baja and Tuscarora and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity.

 

Summary of the Partnership’s Contractual Obligations

 

Yuma Lateral – At the time of our July 1, 2009 acquisition of North Baja from TransCanada, TransCanada had begun an expansion project of the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona. We agreed to acquire the expansion facilities and contracts for an additional sum up to $10.0 million, if TransCanada completed the project by June 30, 2010. On March 5, 2010, we acquired the expansion facilities and contracts in place at that time for a purchase price of $7.6 million.  The Yuma Lateral was placed into service on March 13, 2010.  The North Baja acquisition agreement provides that an additional payment of up to $2.4 million will b e made to TransCanada in the event that any other shippers contract for services on the Yuma Lateral before June 30, 2010.

 

The Partnership’s Debt and Credit Facility

 

The following table summarizes the Partnership’s debt and credit facility outstanding as of March 31, 2010:

 

		Payments Due by Period
(unaudited)                                                                       (millions of dollars)		Total				Less Than 1 Year				Long-term Portion
Senior Credit Facility due 2011			491.0				-				491.0
7.13% Series A Senior Notes due 2010			48.2				48.2				-
7.99% Series B Senior Notes due 2010			4.4				4.4				-
6.89% Series C Senior Notes due 2012			4.7				0.8				3.9
			548.3				53.4				494.9

 

 

The Partnership has a $475.0 million senior term loan and a $250.0 million senior revolving credit facility (together, Senior Credit Facility). There was $491.0 million outstanding under the Senior Credit Facility at March 31, 2010 (December 31, 2009 – $484.0 million). The interest rate on the Senior Credit Facility averaged 0.9 per cent for the three months ended March 31, 2010 (2009 – 2.4 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 4.3 per cent for the three months ended March 31, 2010 (2009 – 5.1 per cent). Prior to hedging activities, the interest rate was 1.1 per cent at March 31, 2010 (2009 – 1.9 per cent). At March 31, 2010, the Partnership was in compliance with all of its financial covenants, in addition to the other covenants which include restricti ons on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

 

 

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Series A, B and C Senior Notes 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. On December 21, 2010, the Series A and B Senior Notes will mature. As market conditions dictate, the Partnership intends to refinance this debt with either fixed-rate or variable-rate debt.

 

Interest Rate Swaps and Options

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk.

 

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $375.0 million at March 31, 2010 (December 31, 2009 – $375.0 million). Under Accounting Standards Codification (ASC) 820 – Fair Value Measurements and Disclosures, financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At March 31, 2010, the fair value of the interest rate swaps accounted for as hedges was negative $22.2 million (December 31, 2009 – negative $23.8 million), of which $13.7 million is classified as a current liability (December 31, 2009 – $12.9 million). The fair value of the interest rate swaps was calculated using the period end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. In the three months ended March 31, 2010, the Partnership recorded interest expense of $4.2 million on the interest rate swaps and options (2009 – $3.2 million).

 

Capital Requirements

 

In the first quarter of 2010, the Partnership made an equity contribution of $2.3 million to Great Lakes, representing the Partnership’s first installment of its 46.45 per cent share of a $10.0 million cash call issued by Great Lakes to expand backhaul capacity from St. Clair to Emerson. The second installment for the remaining balance is due on or before June 30, 2010.

 

On April 22, 2010, the Partnership filed an automatic universal shelf registration statement on Form S-3 (ASR) with the SEC which replaces the universal shelf registration filed in December 2008. The ASR will allow the Partnership to issue an indeterminate amount of securities of the Partnership, including both senior and subordinated debt securities and/or common units representing limited partnership interests in the Partnership. The ASR was effective immediately upon filing and will expire April 22, 2013.

 

To the extent the Partnership has any additional capital requirements with respect to our pipeline systems or makes acquisitions in the future, we expect to fund these requirements with operating cash flows, debt and/or equity.

 

2010 First Quarter Cash Distribution

 

On April 20, 2010, the Partnership announced that the Board of Directors of the general partner declared the Partnership’s first quarter 2010 cash distribution in the amount of $0.73 per common unit. The first quarter cash distribution, totaling $34.4 million, will be paid on May 14, 2010 to unitholders of record as of April 30, 2010 in the following manner: $33.7 million to common unitholders (including $4.2 million to the general partner as holder of 5,797,106 common units and $8.2 million to TransCanada as holder of 11,287,725 common units) and $0.7 million to the general partner in respect of its two per cent general partner interest.

 

 

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LIQUIDITY AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS

 

Overview

 

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, bank credit facilities and equity contributions from their partners. Our pipeline systems fund operating expenses, debt service and cash distributions to partners primarily with operating cash flow.

 

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

 

Our pipeline systems believe that their ability to obtain financing at reasonable rates, together with their history of consistent cash flow from operating activities, provide a solid foundation to meet their future liquidity and capital resource requirements. The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs that allow them to request credit support as circumstances dictate.

 

Summary of Great Lakes’ Contractual Obligations

 

The following table summarizes Great Lakes’ debt outstanding as of March 31, 2010:

 

		Payments Due by Period
(unaudited)                                                                       (millions of dollars)		Total				Less than 1 year				Long-term Portion
8.74% series Senior Notes due 2010 to 2011			20.0				10.0				10.0
6.73% series Senior Notes due 2011 to 2018			72.0				9.0				63.0
9.09% series Senior Notes due 2012 to 2021			100.0				-				100.0
6.95% series Senior Notes due 2019 to 2028			110.0				-				110.0
8.08% series Senior Notes due 2021 to 2030			100.0				-				100.0
			402.0				19.0				383.0

 

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restricted covenants in the Senior Note Agreements, approximately $216.0 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2010 (December 31, 2009 – $221.0 million).  Current maturities will be paid out of operating cash flows.  As at March 31, 2010, Great Lakes was in compliance with all of its financial covenants.

 

Summary of Northern Border’s Contractual Obligations

 

The following table summarizes Northern Border’s debt outstanding as of March 31, 2010:

 

		Payments Due by Period
(unaudited)                                                                       (millions of dollars)		Total				Less than 1 year				Long-term Portion
$250 million credit agreement due 2012			194.0				-				194.0
6.24% Senior Notes due 2016			100.0				-				100.0
7.50% Senior Notes due 2021			250.0				-				250.0
			544.0				-				544.0

 

As of March 31, 2010, Northern Border had outstanding borrowings of $194.0 million under its $250 million revolving credit agreement and was in compliance with the covenants of the agreement.  The weighted average interest rate related to the borrowings on the credit agreement was 0.50 percent at March 31, 2010.

 

 

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CONTINGENCIES

 

Legal

 

On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) in its GL Rate Proceeding indicating that an agreement in principle has been reached among Great Lakes, active participants and the FERC trial staff.  The Motion requests a temporary suspension of the GL Rate Proceeding schedule for all parties to permit the drafting of a stipulation and agreement, and the Motion was granted by the Chief Administrative Law Judge on the same day.  The parties are negotiating the settlement terms and anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC.  Until the filing of the written stipulation and agreement, the terms of the settlement will remain confid ential.  In the absence of a settlement, a hearing in the GL Rate Proceeding is scheduled for early August 2010 and an initial decision by the Administrative Law Judge is expected in November 2010.  Any of the following elements of Great Lakes’ rate structure may be affected in settlement or litigation, including but not limited to: firm transportation, interruptible transportation and/or incremental rates; revenues; depreciation; and interruptible transportation revenue sharing. 

 

Please read Part II, Item 1. “Legal Proceedings” for additional information with respect to this proceeding and the Motion.

 

Environmental

 

On February 2, 2009, Northern Border received a Notice of Violation (NOV) from the EPA alleging that Northern Border was in violation of certain regulations pursuant to the CAA regarding a compressor station on its system. On April 1, 2010, Northern Border received indication from the EPA that it does not intend to file a complaint against Northern Border with respect to the NOV.  Northern Border expects no further action from the EPA regarding this NOV.

 

RELATED PARTY TRANSACTIONS

 

Please read Note 9 within Item 1. “Financial Statements” for additional information regarding related party transactions.

 

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

 

OVERVIEW

 

We are exposed to market risk primarily from interest rate fluctuations. Additionally, the Partnership and our pipeline systems are also exposed to other risks such as credit risk, liquidity risk, foreign exchange fluctuations and changes to natural gas prices related to the calculation of a Minnesota fuel tax, which we have determined to be less material to us and our pipeline systems. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

 

Market risk is the risk of loss arising from adverse changes in market rates. Our primary risk management objective is to protect earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.

 

In accordance with ASC 815 – Derivatives and Hedging, we record financial instruments on the balance sheet as assets and liabilities based on fair value. We estimate the fair value of financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of financial instruments are recognized in earnings unless the instrument qualifies as a hedge under ASC 815 and meets specific hedge accounting criteria. Qualifying financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

 

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MARKET RISK AND INTEREST RATE RISK

 

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

 

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

 

●	Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Partnership and our pipeline systems enter into interest rate swaps to mitigate the impact of changes in interest rates.

●

Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period. The Partnership and our pipeline systems enter into option agreements to mitigate the impact of changes in interest rates.

 

Interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in the market interest rates. Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in London Interbank Offered Rate (LIBOR) interest rates. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

 

Our interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $375.0 million at March 31, 2010 (December 31, 2009 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap for the period from March 12, 2007 through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 per cent. $75.0 million of variable-rate debt is hedged by an interest rate swap for the period from February 29, 2008 through February 28, 2011, where the fixed interest rate paid is 3.86 per cent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility.

 

At March 31, 2010, the fair value of the interest rate swaps accounted for as hedges was negative $22.2 million (December 31, 2009 – negative $23.8 million), of which $13.7 million is classified as a current liability (December 31, 2009 – $12.9 million). The fair value of the interest rate swaps was calculated using the period-end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change.

 

At March 31, 2010, we had $491.0 million (December 31, 2009 – $484.0 million) outstanding on our Senior Credit Facility. Utilizing the conditions of the interest rate swaps, if LIBOR interest rates hypothetically increased by one per cent (100 basis points) compared to the rates in effect at March 31, 2010, our annual interest expense would have increased and our net income would have decreased by $1.2 million; and if LIBOR interest rates hypothetically decreased to zero compared to the rates in effect at March 31, 2010, our annual interest expense would have decreased and our net income would have increased by $0.4 million. These amounts have been determined by considering the impact of the hypothetical interest rates on unhedged debt outstanding as of March 31, 2010.

 

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest rates on its revolving credit facility. Northern Border regularly assesses the impact of interest rate fluctuations on future cash flows and evaluates hedging opportunities to mitigate its interest rate risk. As of March 31, 2010, 64.0 per cent of Northern Border’s outstanding debt was at fixed rates (December 31, 2009 – 62.0 per cent).

 

If interest rates hypothetically increased by one per cent (100 basis points) compared with rates in effect at March 31, 2010, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $2.1 million; and if interest rates hypothetically decreased to zero per cent compared with rates in effect at March 31, 2010, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.5 million.

 

 

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Great Lakes and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to North Baja, as it currently does not have any debt.

 

OTHER RISKS

 

The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price risk with respect to transported natural gas volumes.

 

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Partnership or its pipeline systems. Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. At March 31, 2010, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $8.0 million (December 31, 2009 – $5.4 million).

 

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy parties. Due to the deterioration of global financial markets in 2008 and 2009, we continue to closely monitor the creditworthiness of our counterparties, including financial institutions. Overall, we do not believe the Partnership and our pipeline systems have any significant concentrations of counterparty credit risk.

 

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At March 31, 2010, the Partnership has a committed revolving bank line of $250.0 million maturing in December 2011. As of March 31, 2010, the outstanding balance on this facility was $16.0 million. In addition, at March 31, 2010, Northern Border has a committed revolving bank line of $250.0 million maturing in April 2012. As of March 31, 2010, $194.0 million was drawn on this facility.

 

The state of Minnesota currently requires Great Lakes to pay use tax on the value of the shipper-provided compressor fuel burned in its Minnesota compressor engines. Great Lakes is subject to commodity price volatility and some volume volatility in determining the amount of use tax owed. If natural gas prices changed by $1 per million British thermal units, Great Lakes’ annual use tax expense would change by approximately $0.5 million.

 

The Partnership does not have any material foreign exchange risks.

 

Item 4.    Controls and Procedures

 

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

 

As required by Rule 13a-15(e) under the Exchange Act, the management of our General Partner, including the Principal Executive Officer and Principal Financial Officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures may only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the Principal Executive Officer and Principal Financial Officer, concluded that our disclosure controls and procedures, as of the end of the period covered by this report, were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified by the rules and forms and (b) accumulated and communicated to management of our General Partner, including the Principal Executive Officer and Principal Financial Officer, to allow timely decisions regarding required disclosure.

 

 

 

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Changes in Internal Control over Financial Reporting

 

During the quarter ended March 31, 2010, there has been no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

 

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PART II

 

Item 1.    Legal Proceedings

 

On November 19, 2009, the FERC issued an order in FERC Docket No. RP10-149 (November 2009 Order) instituting an investigation pursuant to Section 5 of the Natural Gas Act (GL Rate Proceeding). The FERC alleged, based on a review of certain historical information, that Great Lakes’ revenues might substantially exceed Great Lakes’ actual cost of service and therefore may be unjust and unreasonable. On February 4, 2010, Great Lakes filed a cost and revenue study (GL Cost and Revenue Study) in response to the November 2009 Order. The GL Cost and Revenue Study reflects the increased risk of de-contracting on the Great Lakes system, which may result in decreases to overall long-term, daily and short-term firm transportation revenues, and interruptible transportation revenues, as compared to prior&# 160;periods.

 

On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) indicating that an agreement in principle has been reached among Great Lakes, active participants and the FERC trial staff.  The Motion requests a temporary suspension of the GL Rate Proceeding schedule for all parties to permit the drafting of a stipulation and agreement, and the Motion was granted by the Chief Administrative Law Judge on the same day.  The parties are negotiating the settlement terms and anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC.  Until the filing of the written stipulation and agreement, the terms of a settlement will remain confidential.  In the absence of a settlement, a hearing in the GL Rate Proceeding is scheduled for early August 2010 and an initial decision by the Administrative Law Judge is expected in November 2010.  Any of the following elements of Great Lakes’ rate structure may be affected in settlement or litigation, including but not limited to: firm transportation, interruptible transportation and/or incremental rates; revenues; depreciation; and interruptible transportation revenue sharing.  A revised rate structure as a result of a settlement, if reached, would be in place as early as the second quarter of 2010.

 

We currently do not expect that the rate case settlement, if reached, will have a material effect on Great Lakes’ revenues in the context of the current market environment.  However, the ultimate impact on revenues will remain confidential until the stipulation and agreement is approved by the Administrative Law Judge and the FERC.

 

In addition to the above written matters, we and our pipeline systems are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business.

 

Item 1A.    Risk Factors

 

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2009.

 

Risks Inherent in Our Business

 

Our pipeline systems are subject to regulation by agencies, including the FERC, which could have an adverse impact on our ability to establish transportation rates that would allow recovery of the full cost of operating our pipeline systems, including a reasonable return, and our ability to make distributions.

 

Under the Natural Gas Act (NGA), interstate transportation rates must be just, reasonable and not unduly discriminatory. Our pipeline systems are subject to extensive regulation by the FERC, the U.S. Department of Transportation, and other federal, state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect our pipeline systems’ profitability. Federal regulation extends to such matters as:

●	rates and charges;

●	operating terms and conditions of service including creditworthiness requirements;

●	types of services our pipeline systems may offer to their customers;

●	construction of new facilities;

●	extension or abandonment of service and facilities;

●	accounts and records;

●	depreciation and amortization policies;

●	income tax allowance policies;

●	acquisition and disposition of facilities;

●	initiation and discontinuation of services;

●	standards of conduct business relations with certain affiliates; and

●	integrity and safety of our pipeline systems and related operations.

 

 

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Given the extent of regulation by the FERC and potential changes to regulations, we cannot predict:

●	the federal regulations under which our pipeline systems will operate in the future;

●	the effect that regulation will have on financial position, results of operations and cash flows of our pipeline systems and ourselves; or

●	whether our cash flow will be adequate to make distributions to unitholders.

 

Tuscarora is currently operating under a rate settlement which precludes a party to the rate settlement from bringing any rate actions prior to May 31, 2010. Northern Border is required to file a new rate proceeding on or before December 31, 2012.

 

On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) in its GL Rate Proceeding indicating that an agreement in principle has been reached among Great Lakes, active participants and the FERC trial staff.  The Motion requests a temporary suspension of the GL Rate Proceeding schedule for all parties to permit the drafting of a stipulation and agreement, and the Motion was granted by the Chief Administrative Law Judge on the same day.  The parties are negotiating the settlement terms and anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC.  Until the filing of the written stipulation and agreement, the terms of the settlement will remain confid ential.  In the absence of a settlement, a hearing in the GL Rate Proceeding is scheduled for early August 2010 and an initial decision by the Administrative Law Judge is expected in November 2010.  Any of the following elements of Great Lakes’ rate structure may be affected in settlement or litigation, including but not limited to: firm transportation, interruptible transportation and/or incremental rates; revenues; depreciation; and interruptible transportation revenue sharing.  Although the terms of the settlement will remain confidential until the filing of the written stipulation and agreement, the terms could adversely affect the cash distributions that Great Lakes makes to us and our ability to make cash distributions to our unitholders.

 

Action by the FERC on currently pending regulatory matters as well as matters arising in the future could adversely affect our pipeline systems' abilities to establish or charge rates that would cover future increase in their costs, such as additional costs related to environmental matters including any climate change regulation, or even to continue to collect rates that cover current costs, including a reasonable return. We cannot assure unitholders that our pipeline systems will be able to recover all of their costs through existing or future rates.

 

Should our pipeline systems fail to comply with all applicable FERC administered statutes, rules, regulations and orders, our pipeline systems could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation.

 

Finally, we cannot give any assurance regarding the future regulations under which our pipeline systems will operate their natural gas transportation businesses or the effect such regulations could ultimately have on our financial condition, results of operations and cash flows.

 

 

 

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Item 6.    Exhibits

 

 

No.                  Description                      

 

10.1	Yuma Transfer Agreement dated March 5, 2010 by and between Gas Transmission Northwest Corporation and North Baja Pipeline, LLC.

31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 30th day of April 2010.

 

TC PIPELINES, LP

(A Delaware Limited Partnership)

by its general partner, TC PipeLines GP, Inc.

 

By: /s/ Mark A.P. Zimmerman                                                   

Mark A.P. Zimmerman

President

TC PipeLines GP, Inc. (Principal Executive Officer)

 

By: /s/ Robert C. Jacobucci                                                   

      Robert C. Jacobucci

Controller

TC PipeLines GP, Inc. (Principal Financial Officer)

 

 

 

 

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Exhibit 10.1

 

 

YUMA TRANSFER AGREEMENT

 

 

    THIS YUMA TRANSFER AGREEMENT (this “Transfer Agreement”) is executed as of this 5th day of March, 2010 by and between GAS TRANSMISSION NORTHWEST CORPORATION, a California Corporation (“Seller”), and NORTH BAJA PIPELINE, LLC, a Delaware limited liability company (“NBLLC”).  Seller and NBLLC are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

 

W I T N E S S E T H

    WHEREAS, Seller and TC PipeLines Intermediate Limited Partnership, a Delaware limited partnership (“TC PipeLines”), have entered into that certain Agreement for Purchase and Sale of Membership Interest, dated as of May 19, 2009 (the “Purchase Agreement”).  Capitalized terms used but not otherwise defined herein shall h ave the meanings given to such terms in the Purchase Agreement;

 

    WHEREAS, pursuant to the Purchase Agreement, TC PipeLines acquired all of Seller’s membership interests in NBLLC on July 1, 2009, such that NBLLC is a wholly-owned subsidiary of TC PipeLines;

 

    WHEREAS, pursuant to the Purchase Agreement, TC PipeLines has agreed to cause NBLLC to consummate the Yuma Transfer upon the terms set forth in the Purchase Agreement; and

    WHEREAS, this Transfer Agreement is being executed and delivered pursuant to the Purchase Agreement and in connection with the consummation of the Yuma Transfer in order to evidence (i) the transfer of the Other Yuma Assets to NBLLC from Seller, and (ii) the transfer of control of the Yuma Assets to NBLLC, all in consideration of the payment of the Yuma Transfer Amount to Seller as provided in the Purchase Agreement.

 

    NOW, THEREFORE, in consideration of the premises, mutual promises and covenants set forth in the Purchase Agreement and hereinafter set forth in this Transfer Agreement and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound hereby, hereby agree as follows:

 

 

ARTICLE I

 

YUMA TRANSFER

 

    1.1 Purchase and Sale of Other Yuma Assets.  For value received, and upon the terms and subject to the conditions of the Purchase Agreement and this Transfer Agreement, (i) Seller does hereby sell, transfer, assign, convey and deliver all of its right, title and interest in and to the Other Yuma Assets to NBLLC, and (ii) NBLLC does hereby purchase, accept and acquire from Seller all of Seller’s right, title and interest in and to the Other Yuma Assets and agree to pay, perform and discharge when due the liabilities related thereto or arising therefrom.  Notwithstanding the foregoing, if an assignment or transfer of any Contract or Permit that is part of the Other Yuma Assets or any claim, right, benefit or obligation thereunder or resulting therefrom, without the consent or approval of a third party thereto, would constitute a breach or violation thereof, result in a material loss or dimunitition thereof or impose any liability on Seller, Seller does not hereby sell, transfer, assign convey or deliver such Contract, Permit, claim, right, benefit or obligation, as applicable, unless and until such consent or approval is obtained; provided, however, that if any such con sent or approval is obtained after the date hereof with respect to any such Contract or Permit, this Transfer Agreement shall constitute an assignment and transfer of the same to NBLLC as of the date of such consent or approval, without any further action by Seller or NBLLC; and provided, further, that with respect to any Contract or Permit that is deemed to not be assigned and transferred as a result of this provision until the necessary consent or approval is obtained, (i) NBLLC shall be provided with the benefits of any such Contract or Permit accruing after the date hereof to the extent (and only to the extent) that Seller may provide such benefits without violating the terms of such Contract or Permit and without incurring any material expense or otherwise taking any material actions or measures, and (ii) NBLLC shall perform at its sole expense the obligations of Seller to be performed after the date hereof under such Contract or Permit to the extent (and only to the extent) that Seller is providing benefits under the Contract or Permit to NBLLC in accordance with clause (i) of this Section 1.1.

 

 

 

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    1.2 Transfer of Control of Yuma Assets.  Effective upon the execution and delivery of this Transfer Agreement, Seller hereby relinquishes control of the Yuma Assets to NBLLC, and NBLLC hereby accepts control of the Yuma Assets, in each case subject to Seller’s rights under Section 9.03 of the Purchase Agreement.

 

    1.3 Receipt of Yuma Transfer Amount.  Seller hereby acknowledges receipt of the Yuma Transfer Amount.

 

 

ARTICLE II

 

REPRESENTATIONS AND WARRANTIES OF SELLER

 

    Except as set forth in any schedule delivered by Seller herewith (it being understood that the provisions of Section 4.09(a) of the Purchase Agreement shall apply to such schedules and to the disclosure of information by Seller hereunder), Seller hereby represents and warrants, as of the date hereof, to NBLLC as follows:

 

    2.1 Incorporation of Certain Representations and Warranties.  The representations and warranties of Seller set forth in the following Sections of the Purchase Agreement are hereby incorporated into this Transfer Agreement and are true and correct as of the date hereof, as modified below:

 

(a) Section 2.01; and

 

(b) Sections 2.02, 2.03, 2.05 and 2.06; provided, that these representations and warranties are made herein by Seller with the following modification:  the term “Transfer Agreement” shall be substituted for the terms “Agreement” and/or “Transaction Agreements,” such that these representations and warranties are hereby made with respect to this Transfer Agreement only.

 

2.2 Title to Yuma Assets.  Except as set forth on Schedule 2.2 to this Transfer Agreement, (i) Seller has good title to, or has valid rights to lease or use, by license, Contract or otherwise, each Other Yuma Asset, free and clear of all Liens and (ii) NBLLC has good title to, or has valid rights to lease or use, by license, Contract or otherwise, each NB Yuma Asset, in each case free and clear of all Liens, exce pt, in the case of each of the foregoing clauses (i) and (ii), for Liens that (x) do not materially interfere with the current use of the applicable Yuma Asset or (y) constitute Permitted Encumbrances.

 

2.3 Condition of Yuma Assets.  The Yuma Assets have been constructed in all Material respects to prevailing industry standards for similar assets and, except as set forth on Schedule 2.3 to this Transfer Agreement, are in satisfactory operating condition and repair, ordinary wear and tear excepted.  There are no capital expenditures currently required in order to preserve the satisfactory operating cond ition of the Yuma Assets, other than (i) as reflected in the NBLLC Budget and (ii) normal maintenance expenditures that are incurred or expected to be incurred in the ordinary course of operating the Yuma Lateral Project. 

 

2.4 Litigation; Observance of Orders.  Except as set forth on Schedule 2.4 to this Transfer Agreement, there are no actions, suits or proceedings pending or, to the Knowledge of Seller, threatened against Seller or NBLLC with respect to the Yuma Lateral Project or the Yuma Assets in any court or before any arbitrator of any kind or before or by any Governmental Authority that would reasonably be expected to have a Material Adverse Effect.

 

2.5 Permits; Intellectual Property.

 

(a) The Permits, patents, copyrights, service marks, trademarks and trade names, or rights thereto, owned or possessed by Seller and transferred to NBLLC hereunder as Other Yuma Assets, together with such assets constituting NB Yuma Assets owned by NBLLC, constitute all such assets necessary for the operation, ownership and maintenance of the Yuma Lateral Project, except where the failure to own or possess the same would not reasonably be expected to have a Material Adverse Effect.  Since the Acquisition Date, neither NBLLC nor Seller has received any written notice that (i) any such Permit, patent, copyright, service mark, trademar k or trade name would be revoked or modified, or (ii) such Permit, patent, copyright, service mark, trademark or trade name would not be renewed in the ordinary course of business.

 

 

 

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(b) Since the Acquisition Date, NBLLC or Seller, as applicable, has made all declarations and filings with the appropriate Governmental Authorities that are necessary for the ownership, maintenance or lease of the Yuma Assets, except where the failure to make the same would not reasonably be expected to have a Material Adverse Effect.

 

2.6 No Violation or Default.  Except as set forth on Schedule 2.6 to this Transfer Agreement, neither NBLLC nor Seller is (i) in default, nor has any event occurred that, with notice or lapse of time or both, would constitute such a default, in the due performance or observance by Seller or NBLLC, as applicable, of any term, covenant or condition contained in any Material Yuma Agreement (as defined in Section 2.7), or (ii) in violation of any law or statute or any judgment, or order, rule or regulation of any court or arbitrator or Governmental Authority in connection with the operation of the Yuma Lateral Project or the Yuma Assets, except, in the case of clauses (i) and (ii) above, for any such default or violation that would not reasonably be expected to have a Material Adverse Effect.  Notwithstanding the foregoing, it is understood and agreed that the representations and warranties set forth in this Section 2.6 shall not apply to (i) matters relating to Permits, declarations and filings (as the sole and exclusive representations and warranties regarding Permits, declarations and filings are set forth in Section 2.5), and (ii) environmental matters (as the sole and exclusive representations and warranties regarding environmental matters are set forth in Section 2.8).

 

2.7 Material Agreements.  The Contracts set forth on Schedule 2.7 to this Transfer Agreement (collectively, the “Material Yuma Agreements”) constitute all Material gas transportation contracts, operation and maintenance agreements, construction contracts and other Material contracts to which NBLLC or Seller is a party or by which NBLLC or Seller is bound or to which any of the Yuma Assets is subject, in each case in connection with the Yuma Lateral Project or the Yuma Assets. The Material Yuma Agreements have been duly authorized, executed and delivered by Seller or NBLLC, as applicable, and constitute valid and legally binding agreements of Seller or NBLLC, as applicable, enforceable against Seller or NBLLC, as applicable, in accordance with their terms, except that such enforceability may be limited by applicable bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors’ rights generally and general equitable principles (whether considered in a proceeding in equity or at law).

 

2.8 Compliance with Environmental Laws.  Except as set forth on Schedule 2.8 to this Transfer Agreement, (a) NBLLC and Seller have operated in compliance with any and all Environmental Laws with respect to the Yuma Lateral Project and the Yuma Assets; (b) NBLLC and Seller have received and are in compliance with all Permits required of them under applicable Environmental Laws to conduct the Yuma Lateral Project a nd to own and operate the Yuma Assets; (c) neither NBLLC nor Seller has been the subject of any outstanding order or judgment from a Governmental Authority under applicable Environmental Laws requiring remediation or payment of a fine in an amount in excess of $500,000 individually or in the aggregate; and (d) neither NBLLC nor Seller has received any written notice of any actual or potential liability for the violation of, or noncompliance with any Environmental Law in connection with the Yuma Lateral Project, or the investigation or remediation of any disposal or release of hazardous or toxic substances or wastes, pollutants or contaminants under any Environmental Law in connection with the Yuma Lateral Project, except in the case of the foregoing clauses (a) and (b) for any such noncom pliance as would not reasonably be expected to have a Material Adverse Effect.  Except for actions and conditions which have not had and would not reasonably be expected to have a Material Adverse Effect, to the Knowledge of Seller no condition exists on any property currently owned or leased by NBLLC which would subject NBLLC or such property to any remedial obligations or liabilities.

 

2.9 Representations with respect to NBLLC.  Notwithstanding anything to the contrary in this Article II, it is understood and agreed that with respect to the period from and after the Closing Seller is making the representations and warranties set forth in this Article II related to NBLLC only to its Kn owledge.

 

 

 

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ARTICLE III

 

REPRESENTATIONS AND WARRANTIES OF NBLLC

 

NBLLC hereby represents and warrants, as of the date hereof, to Seller as follows:

 

3.1 Incorporation of Certain Representations and Warranties.  The representations and warranties set forth in the following Sections of the Purchase Agreement are hereby incorporated into this Transfer Agreement (it being understood that the term “NBLLC” shall be substituted for the term “Buyer” as appropriate so that these representations and warranties, as incorporated herein, are made with respect to NBLLC rather than TC PipeLines) and are true and correct as of the date hereof, as modified by th e foregoing paranthetical and the provisos set forth below:

 

(a) Section 3.01; provided, that this representation and warranty is made herein by and with respect to NBLLC with the following modification:  the term “limited liability company” shall be substituted for the term “limited partnership;” and

 

(b) Sections 3.02, 3.03, 3.04 and 3.05; provided, that these representations and warranties are made herein by and with respect to NBLLC with the following modification:  the term “Transfer Agreement” shall be substituted for the terms “Agreement” and/or “Transaction Agreements,” such that these representations and warranties are hereby made with respect to this Transfer Agreement only).

 

3.2 No Other Representations; Waiver of Implied Warranties.  Except as otherwise provided in this Transfer Agreement, Seller has not made and does not make any other representations or warranties as to the Yuma Assets or the Yuma Lateral Project or any matter or thing affecting or relating to Seller and its businesses, operations, assets, properties, liabilities, financial conditions, results of operation or affairs.  NBLLC hereby waives, to the extent permitted by law, any implied warranty applicable to the tran sactions contemplated hereby (including any implied warranty of merchantability or fitness for a particular purpose).  NBLLC acknowledges that it has had the opportunity to conduct its own independent investigation, analysis and evaluation of the Yuma Assets.

 

 

ARTICLE IV

 

GENERAL PROVISIONS

 

4.1 Indemnification.  For the avoidance of doubt, the Purchase Agreement shall govern the Parties rights and obligations with respect to the representations and warranties set forth herein and the Yuma Transfer generally and shall provide the sole and exclusive remedies of the Parties with respect thereto.

 

4.2 Entire Agreement.  This Transfer Agreement is executed and delivered pursuant to the Purchase Agreement.  The Purchase Agreement and this Transfer Agreement set forth the entire agreement and understanding of the Parties with respect to the Yuma Transfer, and there are no representations, warranties, covenants or agreements other than those expressly set forth herein or therein.  In the event of any conflict between this Transfer Agreement (on the one hand) and the Purchase Agreement (on the other h and), the Purchase Agreement shall control.

 

4.3 Further Assurances.  Seller hereby covenants and agrees that, at any time after the date hereof, upon the written request of NBLLC, Seller shall take or cause to be taken all such necessary action, including the execution and delivery of such further instruments and documents as may reasonably be requested by NBLLC in order to sell, transfer, assign, convey and deliver to NBLLC, its successors and assigns, all right, title and interest in and to the Other Yuma Assets.

 

4.4 Successors and Assigns; Assignment.  This Transfer Agreement shall bind and inure to the benefit of Seller and NBLLC and their respective successors and assigns.

 

 

 

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4.5 Applicable Law.  This Transfer Agreement shall be governed by and construed and enforced in accordance with the laws of the State of New York without giving effect to any choice or conflict of law provision or rule (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of New York.

 

4.6 Counterparts.  This Transfer Agreement may be executed and delivered in one or more counterparts, including facsimile counterparts with originals to follow, each of which shall be deemed to be part of one and the same original document.

 

4.7 Construction.  This Transfer Agreement shall be construed in accordance with the provisions set forth in Sections 10.07, 10.08, 10.12 and 10.13 of the Purchase Agreement.

 

 

 

[SIGNATURE PAGE FOLLOWS]

 

 

 

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IN WITNESS WHEREOF, the Parties hereto have executed this Transfer Agreement as of the date first set forth above.

 

 

 

NORTH BAJA PIPELINE, LLC

 

 

/s/ Sean M. Brett                                               

Name: Sean M. Brett

Title: Vice-President, Commercial Operations

 

/s/ Kelly J. Jameson                                               

Name: Kelly J. Jameson

Title: Secretary

 

GAS TRANSMISSION NORTHWEST CORPORATION

 

/s/ Lee G. Hobbs                                               

Name: Lee G. Hobbs

Title: President

 

/s/ Dean Ferguson                                               

Name: Dean Ferguson

Title: Vice President

 

 

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Exhibit 31.1

 

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

 

I, Mark A.P. Zimmerman, certify that:

 

1.	I have reviewed this Quarterly Report on Form 10-Q of TC PipeLines, LP;

 

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Dated: April 30, 2010

/s/ Mark A.P. Zimmerman                                                                 

Mark A.P. Zimmerman

President

TC PipeLines GP, Inc., as general partner of

TC PipeLines, LP

 

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Exhibit 31.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

 

 

I, Robert C. Jacobucci, certify that:

 

1.	I have reviewed this Quarterly Report on Form 10-Q of TC PipeLines, LP;

 

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Dated: April 30, 2010

/s/ Robert C. Jacobucci                                                                

Robert C. Jacobucci

Principal Financial Officer and Controller

TC PipeLines GP, Inc., as general partner of

TC Pipelines, LP

 

 

 

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Exhibit 32.1

 

 

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

 

 

 

I, Mark A.P. Zimmerman, President of TC PipeLines GP, Inc., the general partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended March 31, 2010 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

 

●	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

●	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

 

Dated: April 30, 2010                                                   /s/ Mark A.P. Zimmerman 

Mark A.P. Zimmerman

President

TC PipeLines GP, Inc., as general partner of

TC PipeLines, LP

 

 

 

 

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Exhibit 32.2

 

 

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

 

 

 

I, Robert C. Jacobucci, Principal Financial Officer and Controller of TC PipeLines GP, Inc., the general partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended March 31, 2010 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

 

●	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

●	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

 

Dated: April 30, 2010                                                  /s/ Robert C. Jacobucci 

Robert C. Jacobucci

Principal Financial Officer and Controller

TC PipeLines GP, Inc., as general partner of

TC PipeLines, LP