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ENBRIDGE ENERGY PARTNERS LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of
operations is based on and should be read in conjunction with our consolidated
financial statements and the accompanying notes included in Item 8. Financial
Statements and Supplementary Data of this Annual Report on Form 10-K.

RESULTS OF OPERATIONS - OVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following activities:

• Interstate pipeline transportation and storage of crude oil and liquid

petroleum; and

• Gathering, treating, processing and transportation of natural gas and

natural gas liquids, or NGLs, through pipelines and related facilities,

along with supply, transportation and sales services, including purchasing

and selling natural gas and NGLs.


We conduct our business through two business segments: Liquids and Natural Gas.
Our Liquids segment includes the operations of our Lakehead, Mid-Continent and
North Dakota
 systems. These systems largely consist of Federal Energy Regulatory
Commission, or FERC, regulated interstate crude oil and liquid petroleum
pipelines, gathering systems and storage facilities. The Lakehead system,
together with the Enbridge system in 
Canada
, forms the longest liquid petroleum
pipeline system in the world. Our Liquids systems generate revenues primarily
from charging shippers a rate per barrel to gather, transport and store crude
oil and liquid petroleum.

Our Natural Gas segment includes natural gas and NGL gathering and
transportation pipeline systems, natural gas processing and treating facilities,
condensate stabilizers and an NGL fractionation facility. Moreover, our Natural
Gas segment also provides supply, transmission, storage and sales services to
producers and wholesale customers on our natural gas gathering, transmission and
customer pipelines, as well as other interconnected pipeline systems. Revenues
for our Natural Gas segment are determined primarily by the volumes of natural
gas gathered, compressed, treated, processed, transported and sold through our
systems; the volumes of NGLs sold; and the level of natural gas, NGL and
condensate prices. Additionally, we provide other services that are valued by
our customers. Segment gross margin is derived from the compensation we receive
from customers in the form of fees or commodities we receive for providing
services in addition to the proceeds we receive for sales of natural gas, NGLs
and condensate to affiliates and third-parties.

The following table reflects our operating income by business segment and
corporate charges for each of the years ended December 31, 2015, 2014 and 2013:

[[Image Removed]]         [[Image Removed]]      [[Image Removed]]      [[Image Removed]]
                                                     December 31,
                                  2015                   2014                   2013
                                                    (in millions)
Operating income (loss)
Liquids                   $         994.0        $         938.9        $         392.6
Natural Gas                        (298.0 )                158.4                   55.4
Corporate, operating
and administrative                  (14.4 )                (10.6 )                 (7.6 )
Total operating income              681.6                1,086.7                  440.4
Interest expense                   (322.0 )               (403.2 )               (320.4 )
Allowance for equity
used during
construction                         70.3                   57.2                   43.1
Other income                         29.3                    8.9                   16.0
Income tax expense                   (4.9 )                 (9.6 )                (18.7 )
Net income                          454.3                  740.0                  160.4
Less: Net income
attributable to:
 Noncontrolling
interest                            221.1                  263.3                   88.3
 Series 1 preferred
unit distributions                   90.0                   90.0                   58.2
 Accretion of discount
on Series 1 preferred
units                                11.2                   14.9                    9.2
Net income attributable
to general and limited
partner ownership
interests in Enbridge
Energy Partners, L.P.     $         132.0        $         371.8        $           4.7


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Highlights
Liquids

Our Liquids segment operating income increased $55.1 million for the year ended
December 31, 2015, as compared with the same period in 2014, primarily due to
additional assets placed in service and an increase in volumes on our systems.
In 2014 and 2015, $2.7 billion and $1.6 billion of additional assets,
respectively, were placed into service on our Lakehead system, including
portions of the Eastern Access, Mainline Expansion projects and other projects.
Average daily volumes delivered on our liquids systems increased 249,000 Bpd, or
9.46%, for the year ended December 31, 2015, when compared with the same period
in 2014, due to increased capacity. Lastly, the Liquids segment operating income
increased as a result of reduced environmental costs, net of recoveries,
primarily due to lower environmental accruals, net of recoveries, related to the
Line 6B crude oil release.

Natural Gas

Our Natural Gas segment operating income decreased $456.4 million for the year
ended December 31, 2015, as compared to the same period in 2014, primarily as a
result of a non-cash goodwill impairment charge of $246.7 million that was
recorded during the second quarter of 2015. In addition, segment gross margin
experienced a net decrease of $216.8 million, due to non-cash, mark-to-market
losses of $58.3 million for the year ended December 31, 2015, as compared to
gains of $158.5 million for year ended December 31, 2014. Furthermore, there
were declines in natural gas pricing differentials and production volumes for
the year ended December 31, 2015, when compared to the same period in 2014,
primarily due to the current low commodity pricing environment. We expect that
the lower commodity price trends will continue through 2016. These decreases in
segment gross margin were offset by over $70.0 million of workforce and other
cost reductions for the year ended December 31, 2015.

Derivative Transactions and Hedging Activities

Contractual arrangements in our Liquids, Natural Gas, and Corporate segments
expose us to market risks associated with changes in (1) commodity prices where
we receive crude oil, natural gas or NGLs in return for the services we provide
or where we purchase natural gas or NGLs and (2) interest rates on our variable
rate debt. Our unhedged commodity position is fully exposed to fluctuations in
commodity prices, which can be significant during periods of price volatility.
We use derivative financial instruments such as futures, forwards, swaps,
options and other financial instruments with similar characteristics, to manage
the risks associated with market fluctuations in commodity prices and interest
rates, as well as to reduce variability in our cash flows. Based on our risk
management policies, all of our derivative financial instruments are employed in
connection with an underlying asset, liability and/or forecasted transaction and
are not entered into with the objective of speculating on commodity prices or
interest rates. Derivative financial instruments that do not receive hedge
accounting under the provisions of authoritative accounting guidance create
volatility in our earnings that can be significant. However, these fluctuations
in earnings do not affect our cash flow. Cash flow is only affected when we
settle the derivative instrument.

We record all derivative instruments in our consolidated financial statements at
fair market value pursuant to the requirements of applicable authoritative
accounting guidance. We record changes in the fair value of our derivative
financial instruments that do not receive hedge accounting in our consolidated
statements of income as follows:

• Liquids segment commodity-based derivatives - "Transportation and other

services" and "Power"

• Natural Gas segment commodity-based derivatives - "Commodity sales" and

"Commodity costs"

• Corporate interest rate derivatives - "Interest expense"

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The changes in fair value of our derivatives are also presented as a reconciling
item on our consolidated statements of cash flows. The following table presents
the net changes in fair value associated with our derivative financial
instruments:

[[Image Removed]]      [[Image Removed]]       [[Image Removed]]      [[Image Removed]]
                                                   December 31,
                               2015                    2014                   2013
                                                  (in millions)
Liquids segment:
Non-qualified hedges   $         (15.5 )       $          13.6        $          (3.9 )
Natural Gas segment:
Hedge
ineffectiveness                   (4.1 )                   5.6                    3.3
Non-qualified hedges             (54.2 )                 152.9                   (6.3 )
Commodity derivative
fair value net gains
(losses)                         (73.8 )                 172.1                   (6.9 )
Corporate:
Interest rate hedge
ineffectiveness                   98.9                  (100.1 )                (21.5 )
Non-qualified
interest rate hedges                 -                       -                   (0.2 )
Derivative fair
value net gains
(losses)               $          25.1         $          72.0        $         (28.6 )


RESULTS OF OPERATIONS - BY SEGMENT
Liquids

Our Liquids segment includes the operations of our Lakehead, 
North Dakota
 and
Mid-Continent systems. We provide a detailed description of each of these
systems in Item 1. Business. The following table sets forth the operating
results and statistics of our Liquids segment assets for the periods presented:

[[Image Removed]]           [[Image Removed]]     [[Image Removed]]     [[Image Removed]]
                                                     December 31,
                                   2015                  2014                  2013
                                                     (in millions)
Operating Results:
Operating revenue           $         2,303.4     $         2,070.4     $         1,519.9
Operating expenses:
Environmental costs, net
of recoveries                             3.1                  97.3                 273.7
Operating and
administrative                          605.9                 500.8                 461.0
Power                                   259.5                 226.6                 147.7
Asset Impairment                         62.5                     -                     -
Depreciation and
amortization                            378.4                 306.8                 244.9
Total operating expenses              1,309.4               1,131.5               1,127.3
Operating income            $           994.0     $           938.9     $           392.6
Operating Statistics
Lakehead system:
United States(1)                        1,869                 1,669                 1,427
Province of Ontario(1)                    446                   444                   389
Total Lakehead system
delivery volumes(1)                     2,315                 2,113                 1,816
Barrel miles (billions)                   640                   582                   487
Average haul (miles)                      757                   755                   735
Mid-Continent system
delivery volumes(1)                       212                   200                   201
North Dakota
 system:
Trunkline(1)                              351                   315                   168
Gathering(1)                                2                     3                     3
Total 
North Dakota
 system
delivery volumes(1)                       353                   318                   171
Total Liquids segment
delivery volumes(1)                     2,880                 2,631                 2,188


[[Image Removed]]

(1) Average barrels per day in thousands.

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Year ended December 31, 2015 compared with year ended December 31, 2014

Operating income of our Liquids segment for the year ended December 31, 2015,
increased $55.1 million, as compared with the same period in 2014, primarily due
to the reasons discussed below.

Operating revenue increased $233.0 million for the year ended December 31, 2015,
when compared with the same period in 2014, primarily due to the following
reasons. Operating revenue increased $25.2 million, primarily due to higher
average rates. Operating revenue also increased $223.8 million from increased
surcharge revenue for projects on our Lakehead system subject to regulatory
accounting, primarily as a result of placing $2.7 billion and $1.6 billion of
assets into service on the Lakehead system in 2014 and 2015, respectively. These
additional assets placed into service included components of the Eastern Access,
Mainline Expansion Projects and other expansion projects. This amount was
partially offset by a $101.4 million decrease in rates due to greater qualifying
volume credits related to Lakehead toll revenues. Qualifying volume credits
represent a contractual obligation, which were introduced with the original
Southern Access and Alberta Clipper expansions, to return a portion of revenue
to our shippers when volumes shipped exceed certain predetermined levels. Once
these predetermined levels are exceeded, the expansion projects are earning
their full cost-of-service. Hence, to limit project earnings to agreed levels,
the credits are returned to the shippers through the tolls.

Operating revenue also increased $87.0 million due to increased average daily
delivery volumes. Volumes delivered increased 249,000 Bpd, of which 202,000 Bpd
and $72.3 million were attributable to higher volumes on our Lakehead system as
a result of additional system capacity from the aforementioned assets that were
placed into service. The 
North Dakota
 system experienced an increase of 35,000
Bpd and $12.7 million in revenues due to our system's enhanced market access in
addition to volumes shifting onto this system and away from higher cost
alternatives such as transportation by rail. Additionally, our operating revenue
also increased by $25.0 million due to a surcharge that went into effect on
April 1, 2015, which is designed to recover half of the costs of a hydrostatic
test on Line 2B.

Increases to operating revenue were also partially offset by decreased non-cash,
mark-to-market net gains of $28.4 million related to derivative financial
instruments. The decrease is primarily the result of a $19.4 million
reclassification of previously recognized unrealized mark-to-market net gains
where the underlying transactions were settled, coupled with $9.0 million of
decreased non-cash, mark-to-market net gains due to smaller decreases in average
forward prices during 2015 than during 2014.

Environmental costs, net of recoveries, decreased $94.2 million for the year
ended December 31, 2015 when compared with the same period in 2014. This
decrease is primarily related to cost accruals for the Line 6B crude oil
release. During the year ended December 31, 2015, there were no cost accruals
for the Line 6B crude oil release. For the same period ended 2014, there were
$85.9 million of cost accruals.

Operating and administrative expenses increased $105.1 million for the year
ended December 31, 2015, when compared with the same period in 2014, primarily
due to $64.2 million of pipeline integrity costs. The increase in pipeline
integrity costs is primarily due to $79.1 million of costs in 2015 for the
hydrostatic test on Line 2B. Pipeline integrity costs were partially offset by a
$14.9 million decrease in other integrity costs.

Additionally, the increase in operating and administrative expenses was also due
to cost increases of $18.9 million of property taxes, $15.3 million of workforce
related costs and $6.8 million of other operating and administrative expenses,
mainly consisting of contract labor, insurance, rents and lease payments, and
professional and regulatory services. These cost increases primarily result from
the additional assets placed into service during 2014 and 2015.

Power costs increased $32.9 million for the year ended December 31, 2015 when
compared with the year ended 2014, primarily as a result of increased volumes on
our systems.

During the year ended December 31, 2015, we recorded a non-cash impairment loss
of $62.5 million to write off the remaining carrying value of our 
Berthold
 rail
facility due to contracts that have not been renewed subsequent to 2016. There
were no such asset impairment charges for the year ended December 31, 2014.

The increase in depreciation expense of $71.6 million for the year ended December 31, 2015, when compared with the same period in 2014, is directly attributable to additional assets placed into service, primarily on projects discussed above.

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Year ended December 31, 2014 compared with year ended December 31, 2013

Operating revenue of our Liquids segment increased $550.5 million for the year
ended December 31, 2014, when compared with the same period in 2013, primarily
due to the filing of tariffs to increase the rates for our Lakehead, 
North Dakota
 and 
Ozark
 systems with the FERC. These rate increases became effective on
April 1 and July 1, 2014, for our 
North Dakota
 and 
Ozark
 systems, and August 1,
2014, for our Lakehead system. The increase in rates accounted for $339.5
million of the increase in operating revenue for the year ended December 31,
2014, when compared to December 31, 2013. The large increase in rates is
primarily due to $2.7 billion of additional assets placed into service in 2014
on the Lakehead system, including the Eastern Access, Mainline Expansion and
other expansion projects. Additionally, 2014 revenues increased from a full year
of revenue for Lakehead and 
North Dakota
 expansion projects placed into service
during 2013. The rate increases effective April 1, 2014, primarily resulted from
annual tariff filings for our 
North Dakota
 and 
Ozark
 systems to reflect our
projected costs and throughput for 2014 and adjustments for the prior year. The
rate increases effective July 1, 2014, resulted from an annual index rate filing
to adjust base rates for our 
North Dakota
 and 
Ozark
 systems in compliance with
rate ceilings allowed by the FERC. The rate increases effective August 1, 2014,
resulted from tariff filings for our Lakehead system to reflect our projected
costs and throughput for 2014, adjustments for the prior year, and an indexing
adjustment to base rates in compliance with the indexed rate ceilings allowed by
the FERC. Historically, the Lakehead system's annual tariff filing has been
effective April 1 and its annual index rate filing has been effective July 1;
however, the filings were delayed due to negotiations with CAPP concerning
certain components of the tariff rate structure.

Operating revenue also increased for the year ended December 31, 2014, when
compared to the same period in 2013, by $139.9 million due to increased average
daily delivery volumes on our Lakehead and 
North Dakota
 systems. Average daily
volumes delivered on our liquids systems increased 443,000 Bpd for the year
ended December 31, 2014, compared to the year ended December 31, 2013. Of that
amount, our Lakehead system realized higher daily volumes of 297,000 Bpd, which
contributed to increased revenue of $75.7 million. This increase in volumes is
attributable to a combination of increased supply from 
Western Canada
 and
additional capacity on our system from the assets placed into service in 2014 as
discussed above. The 
North Dakota
 system also experienced an increase of 147,000
Bpd primarily due to narrowing market pricing differentials from 
North Dakota
 to
major market centers. This reduction in pricing differentials shifted volumes
onto our 
North Dakota
 system and away from rail competitors.

Additionally, operating revenue increased during the year ended December 31,
2014, when compared to the same period in 2013, due to an increase of $17.6
million primarily from our Berthold Rail System that was placed into service in
March 2013.

Operating revenue increased for the year ended December 31, 2014, when compared
with the same period in 2013, due to an increase of $24.2 million in ship-or-pay
contracts on our 
North Dakota
 and Bakken systems. This is primarily due to
increased committed volumes for certain shippers.

Additionally, operating revenue increased as a result of increases of $17.3
million of non-cash, mark-to-market net gains related to derivative financial
instruments. The increase is the result of $2.3 million in realized gains
related to our settled derivative financial instruments, coupled with $15.0
million of non-cash, mark-to-market net gains due to decreases in average
forward prices of crude oil during 2014, compared to increases in the average
forward prices of crude oil during 2013.

Environmental costs, net of recoveries, decreased $176.4 million for the year
ended December 31, 2014, when compared with the same period in 2013, primarily
due to lower environmental accruals, net of recoveries, related to the Line 6B
crude oil release. During the year ended December 31, 2014, we recognized $85.9
million in cost accruals compared to $302.0 million for the comparable period
ended December 31, 2013. There were no insurance recoveries during 2014 compared
to $42.0 million during 2013.

Operating and administrative expenses increased $39.8 million for the year ended
December 31, 2014, when compared with the same period in 2013, primarily due to:
$40.4 million of workforce related costs; $18.6 million of property taxes; and
$34.3 million of other operating and administrative expenses, mainly consisting
of contract labor, insurance, rents and lease payments, and professional and
regulatory services. These cost increases primarily result from the additional
assets placed into service during 2014. The increase in operating and
administrative expenses is offset by a decrease of $53.9 million of pipeline
integrity costs primarily due to $57.7 million of costs incurred for a
hydrostatic test we performed on Line 14 during 2013 that did not occur again
during 2014.

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Power costs increased $78.9 million for the year ended December 31, 2014, when
compared to the year ended December 31, 2013, primarily as a result of increased
volumes on our systems.

The increase in depreciation expense of $61.9 million for the year ended
December 31, 2014, is directly attributable to additional assets placed into
service, primarily on projects discussed above. The increase in depreciation
expense was offset by a $12.6 million reduction due to depreciation studies we
completed during the fourth quarter of 2013 for our 
North Dakota
 and 
Ozark
systems. The depreciation studies extended the asset lives due to additional
reserve growth and pipeline connectivity needs, and the total impact of these
studies is a reduction of annual depreciation expense of $16.8 million on a
prospective basis.

Future Prospects Update for Liquids

We currently have a multi-billion dollar growth program underway, with projects
coming into service through early 2019, in addition to options to increase our
economic interest in projects that are jointly funded by us and Enbridge.
Furthermore, Enbridge has a large inventory of 
United States
 liquids pipelines
assets and continues to evaluate selective drop down opportunities of
approximately $500 million annually, subject to market conditions and our
financing capacity.

Impact of Commodity Price Declines

Volatility in commodity prices can impact production volumes in the oil sands
region of 
Western Canada
 and the Bakken region of 
North Dakota
, our two primary
crude oil supply basins.

The relatively high costs and large up-front capital investments required by oil
sands projects involves significant assumptions around short-term and long-term
crude oil fundamentals, including world supply and demand, North American supply
and demand, and price outlook, among many other factors. As oil sands production
is long-term in nature, the long-term outlook is significant to a producer's
investment decision. In the near-term, the current pricing environment is not
expected to materially impact projected growth from the oil sands region.

We expect that the current crude oil price downturn may result in deferral of
some oil sands projects, particularly if the current pricing environment
continues throughout 2016. However, we expect that projects already under
construction will be finished and enter production. In addition, current
production volumes from the oil sands are unlikely to decrease absent an
operational upset at one of the oil sands operations. Accordingly, we do not
anticipate significant changes in our short-term crude oil volume outlook from
the oil sands. Our long-term growth in volumes and additional infrastructure
expansion will depend on long-term fundamentals. During this period of
uncertainty, we believe our pipeline systems are ideally positioned to capture
incremental pipeline capacity needs with lower cost, smaller scale expansions of
our large Lakehead, 
North Dakota
 and Mid-Continent pipeline systems.

Tight sands oil production in any basin in 
North America
 will be comparatively
more sensitive to the short-term changes in commodity prices due to the
production profile associated with tight sands oil wells. Accordingly, we expect
a reduction in the growth rate for North American tight sands and shale oil. We
believe that rail will be the source of transportation most directly impacted by
any declines in production due to its comparatively higher cost relative to
pipeline transportation.

Financial impacts to our pipeline systems, in the event the rate of growth were
to slow or volumes were to decline, is partially offset by our cost-of-service
agreements, toll structures and existing demand to transport crude oil from
existing production. We do not believe that the decline in crude oil prices will
impact our liquids segment meaningfully in the short-term. However, a long-term
decline in crude oil prices could have a more significant impact on future
production and our rate of growth.

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Expansion Projects

The table and discussion below summarizes our commercially secured projects for the Liquids segment that have been recently placed into service or will be placed into service in future periods:

[[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]]

                     Total Estimated Capital
Projects                      Costs               In-Service Date            Funding
                          (in millions)
Line 3 Replacement
Program(1)           $               2,600        Early 2019                    EEP (2)
Sandpiper
Project(1)                           2,600        Early 2019                  Joint (3)
Eastern Access
Projects:
Eastern Access
Upsize - Line 6B
Expansion                              310        Mid-2016                    Joint (4)
U.S. Mainline
Expansions:
Chicago Area
Connectivity (Line                                Fourth quarter
78)                                    540        2015                        Joint (5)
Line 61 (800,000                                  Second quarter
Bpd capacity)                          395        2015                        Joint (5)
Line 61                                           Third quarter
(Additional                                       2015 - Third
tankage)                               380        quarter 2016                Joint (5)
Line 61 (1,200,000
Bpd capacity)(6)                       485        Early 2019                  Joint (5)
Line 67                                           Third quarter
                                       240        2015                        Joint (5)


[[Image Removed]]

(1) Estimated in-service dates and capital costs are pending regulatory and

      other approvals.


  (2) A special committee of independent directors of the Board of Enbridge

Management has been established to consider a joint funding agreement with

Enbridge.

(3) Jointly funded 62.5% by us and 37.5% by Williston Basin Pipeline LLC, an

affiliate of Marathon Petroleum Corp., under the North Dakota Pipeline

Company Amended and Restated Limited Liability Company Agreement. Estimated

capital costs are presented at 100% before Williston's contributions.

(4) Jointly funded 25% by the Partnership and 75% by our General Partner under

      Eastern Access Joint Funding Agreement. Estimated capital costs are
      presented at 100% before our General Partner's contributions.

(5) Jointly funded 25% by the Partnership and 75% by our General Partner under

      Mainline Expansion Joint Funding Agreement. Estimated capital costs are
      presented at 100% before our General Partner's contributions.

(6) Estimated in-service date will be adjusted to coincide with the in-service

date of the Sandpiper Project and the impact of cost to be reviewed.

Line 3 Replacement Program

On March 3, 2014, we and Enbridge announced that shipper support was received to
replace portions of the existing 1,031-mile Line 3 pipeline on the Canadian
Mainline/Lakehead system between 
Hardisty, Alberta, Canada
 and 
Superior, Wisconsin
. Our portion of the Line 3 Replacement Program, referred to as the US
L3R Program, includes replacing 358 miles from the 
U.S.
/Canadian border at
Neche, North Dakota
 to 
Superior, Wisconsin
. While the L3R Program will not
provide an increase in the overall capacity of the mainline system, it will
support the safety and operational reliability of the system, enhance
flexibility and allow us and Enbridge to optimize throughput on the mainline
system from 
Western Canada
 into 
Superior, Wisconsin
.

We are in the process of obtaining the appropriate permits for constructing the
US L3R Program in 
Minnesota
. The project requires both a Certificate of Need, or
Certificate, and an approval of the pipeline's route, or Route Permit, from the
Minnesota Public Utilities Commission, or MNPUC. The MNPUC found both the
Certificate and Route Permit applications for the US L3R Program through
Minnesota
 to be complete. The MNPUC had sent the Certificate application to the
Administrative Law Judge, or ALJ, for a pre-hearing meeting to establish a
schedule. With respect to the Route Permit, the Minnesota Department of Commerce
held public scoping meetings in August 2015. As a result of the Minnesota Court
of Appeals decision for the Sandpiper Project, the ALJ requested direction on
how to proceed with the Certificate process for Line 3. On February 1, 2016, the
MNPUC issued a written order, or the US L3R Order, joining the Line 3
Certificate and Route Permit dockets and requiring the Department of Commerce to
prepare an Environmental Impact Statement, or EIS, before the Certificate and
Route Permit processes commence, and sent the cases to the Office of
Administrative Hearings, or OAH, with direction to restart the process. We
believe that the directions from the MNPUC in most of the decisions set out in
the US L3R Order were consistent with expectations and provide clarity on
process matters; however, we believe the requirement to have a final EIS prior
to beginning the Certificate and Route Permit processes is unprecedented and
contrary to 
Minnesota
 law. On February 5, 2016, we filed a Petition for
Reconsideration of this aspect of the US L3R Order. If upheld, the US L3R Order
will result in delays in the processing of the applications and an increase in
the costs of the project.

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Subject to regulatory and other approvals, the US L3R Program is now expected to
be completed in early 2019. We continue to review the impact of this order on
the US L3R Program's schedule and cost estimates. A special committee of
independent directors of the board of Enbridge Management has been established
to consider a proposal from our General Partner, on behalf of Enbridge, that
would establish joint funding arrangements for the US L3R Program by creating an
additional jointly owned series of partnership interests in Enbridge Energy,
Limited Partnership, or OLP, similar to the series established for Eastern
Access and Mainline Expansion.

We will recover our costs based on our existing Facilities Surcharge Mechanism,
or FSM, with the initial term being 15 years. For purposes of the toll
surcharge, the agreement specifies a 30 year recovery of the capital based on a
cost-of-service methodology.

Light Oil Market Access Program

We and Enbridge have invested in a Light Oil Market Access Program to expand
access to markets for growing volumes of light oil production. This program
responds to significant recent developments with respect to supply of light oil
from 
U.S.
 north central formations and western 
Canada
, as well as refinery
demand for light oil in the 
U.S.
 Midwest and eastern 
Canada
. The Light Oil
Market Access Program includes several projects that will provide increased
pipeline capacity on our 
North Dakota
 regional system, further expand capacity
on our 
U.S.
 mainline system, upsize the Eastern Access Project, enhance
Enbridge's Canadian mainline terminal capacity and provide additional access to
U.S.
 Midwestern refineries.

Sandpiper Project

Included in the Light Oil Market Access Program is the Sandpiper Project which
will expand and extend the 
North Dakota
 feeder system by 225,000 Bpd to a total
of 580,000 Bpd. The proposed expansion will involve construction of an
approximate 600-mile pipeline from Beaver Lodge Station near 
Tioga, North Dakota
to the 
Superior, Wisconsin
 mainline system terminal. The new line will twin the
existing 210,000 Bpd North Dakota system mainline, which now terminates at
Clearbrook Terminal in 
Minnesota
, adding 250,000 Bpd of capacity on the twin
line between 
Tioga
 and 
Berthold, North Dakota
 and 225,000 Bpd of capacity on the
twin line between 
Berthold
 and 
Clearbrook
 both with a new 24-inch diameter
pipeline, in addition to adding 375,000 Bpd between 
Clearbrook
 and 
Superior
 with
a new 30-inch diameter pipeline.

We are in the process of obtaining the appropriate permits for the construction
of the Sandpiper Project in 
Minnesota
. The project requires both a Certificate
and Route Permit from the MNPUC. On August 3, 2015, the MNPUC issued an order
granting a Certificate and a separate order restarting the Route Permit
proceedings. On September 14, 2015, the Minnesota Court of Appeals reversed the
MNPUC's Certificate order stating that an EIS must be prepared prior to reaching
a final decision in cases where proceedings have been separated and handled
sequentially. On January 11, 2016, the MNPUC issued a written order, or the
Sandpiper Order, rejoining the Certificate and Route Permit process, requiring
the Department of Commerce to commence preparation of an EIS, ordering the OAH
to recommence processing the Certificate and Route Permit applications but to
take judicial notice of the record already developed for the Certificate, and
requiring that a final EIS be issued before the Certificate and Route Permit
processes commence. We believe that the directions from the MNPUC in most of the
decisions set out in the Sandpiper Order were consistent with expectations and
provide clarity on process matters; however, we believe the requirement to have
a final EIS prior to beginning the Certificate and Route Permit processes is
unprecedented and contrary to 
Minnesota
 law. On February 1, 2016, we filed a
Petition for Reconsideration for this aspect of the Sandpiper Order. If upheld,
the Sandpiper Order will result in delays in processing of the applications and
an increase in the cost of the project. Subject to regulatory and other
approvals, we estimate that the in-service date for the Sandpiper Project will
occur in early 2019. We continue to review the impact of the Sandpiper Order on
the project's schedule and cost estimates.

Marathon Petroleum Corporation, or MPC, has been secured as an anchor shipper
for the Sandpiper Project. As part of the arrangement, we, through our
subsidiary, North Dakota Pipeline Company LLC, or NDPC, and Williston Basin
Pipeline LLC, or Williston, an affiliate of MPC, entered into an agreement to,
among other things, admit Williston as a member of NDPC. Williston will fund
37.5% of the Sandpiper Project construction and have the option to participate
in other growth projects within NDPC, unless specifically excluded by the
agreement; this investment is not to exceed $1.2 billion in aggregate. In return
for funding part of Sandpiper's construction, Williston will obtain an
approximate 27% equity interest in NDPC at the in-service date of Sandpiper.

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Eastern Access Projects

Since October 2011, we and Enbridge have announced multiple expansion projects
that will provide increased access to refineries in the 
U.S.
 Upper Midwest and
the Canadian provinces of 
Ontario
 and 
Quebec
 for light crude oil produced in
western 
Canada
 and 
the United States
. As part of the Light Oil Market Access
Program announced in 2012, we announced a further expansion project of Line 6B
to increase capacity from 500,000 Bpd to 570,000 Bpd and to include: pump
station modifications at 
Griffith
, 
Niles
 and 
Mendon
, 
Indiana
; additional
modifications at the 
Griffith
 and 
Stockbridge, Michigan
 terminals; and breakout
tankage at 
Stockbridge
. The expected cost of this expansion is approximately
$310 million and is expected to be placed into service in mid-2016. This project
is being funded 75% by our General Partner and 25% by us under the Eastern
Access Joint Funding Agreement. Within one year of the in-service date, we will
have the option to increase our economic interest by up to 15% at cost. The
Eastern Access Projects, which includes the Line 6B Expansion project along with
the previously completed Line 5 Expansion, Line 62 Expansion and the Line 6B
Replacement projects, will cost approximately $2.7 billion.

U.S.
Mainline Expansions
In 2012 and 2013, we announced further expansion projects for our mainline
pipeline system including: (1) expanding our existing 36-inch diameter Alberta
Clipper pipeline, or Line 67; (2) expanding our existing 42-inch diameter
Southern Access pipeline, or Line 61; and (3) expanding by constructing Line 78,
a twin of Line 62.

The current scope of the Line 67 pipeline expansion between 
Neche, North Dakota
and the Superior, Wisconsin Terminal consists of two phases. The initial phase
increased capacity from 450,000 Bpd to 570,000 Bpd at an estimated cost of
approximately $220 million. The second phase added an additional 230,000 Bpd of
capacity at an estimated cost of approximately $240 million. The initial phase
was completed in the third quarter of 2014 and the second phase was completed in
July 2015. Both phases of the Line 67 pipeline expansion required only the
addition of pumping horsepower, with no pipeline construction, and are subject
to regulatory and other approvals, including an amendment to the current
Presidential border crossing permit to allow for operation of the Line 67
pipeline at its currently planned operating capacity of 800,000 Bpd. We continue
to work with regulatory authorities; however, the timing of the receipt of the
amendment to the Presidential border crossing permit to allow for increased flow
on the Line 67 pipeline across the border cannot be determined at this time. A
number of temporary system optimization actions have been undertaken to
substantially mitigate any impact on throughput associated with any delays in
obtaining this amendment.

In November of 2014 several environmental and Native American groups filed a
complaint in the United States District Court in 
Minnesota
 against the United
States Department of State, or DOS. The Complaint alleges, among other things,
that the DOS is in violation of the National Environmental Policy Act by
acquiescing in Enbridge's use of permitted cross border capacity on other lines
to achieve the transportation of amounts in excess of Line 67's current
permitted capacity while the review and approval of Enbridge's application to
the DOS to increase Line 67's permitted cross border capacity is still pending.
On December 9, 2015, the District Court ruled that the DOS interpretation of
Enbridge's Presidential permits is not reviewable by a federal court on
constitutional grounds.

The current scope of the Southern Access expansion, or Line 61 expansion,
between 
Superior, Wisconsin
 and 
Flanagan, Illinois
 also consists of phases that
require only the addition of pumping horsepower with no pipeline construction.
The initial phase to increase the capacity from 400,000 Bpd to 560,000 Bpd was
completed in August 2014 at a cost of approximately $160 million. We further
expanded the pipeline capacity to 800,000 Bpd in May 2015 at an estimated cost
of approximately $395 million. Additional tankage is expected to cost
approximately $380 million with various completion dates that began in the third
quarter of 2015 and are expected to continue through the third quarter of 2016.
In the first quarter of 2015, we, in conjunction with shippers, decided to delay
the in-service date of a further expansion phase to increase the pipeline
capacity to 1,200,000 Bpd to align more closely with the anticipated in-service
date for the Sandpiper Project. In October 2015, a portion of this phase was
placed into service early to address capacity constraints, increasing pipeline
capacity to 950,000 Bpd. The remaining capacity is expected to be placed into
service in line with the expected in-service date of the Sandpiper Project.

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Furthermore, as part of the Light Oil Market Access Program, we expanded the
capacity on our Lakehead System between 
Flanagan, Illinois
, and 
Griffith, Indiana
 by constructing Line 78, a 79-mile, 36-inch diameter twin of Line 62,
with an initial capacity of 570,000 Bpd, at an estimated cost of $540 million.
Line 78 was placed into service in November 2015.

These projects, collectively referred to as the 
U.S.
 Mainline Expansions
projects, are expected to cost approximately $2.4 billion. We will operate the
projects on a cost-of-service basis. These projects are jointly funded 75% by
our General Partner and 25% by us under the Mainline Expansion Joint Funding
Agreement, which parallels the Eastern Access Joint Funding Agreement. We have
the option to increase our economic interest held up to 15% at cost.

Canadian Eastern Access and Mainline Expansion Projects

The Eastern Access Projects and 
U.S.
 Mainline Expansions projects complement
Enbridge's strategic initiative of expanding access to new markets in 
North America
 for growing production from western 
Canada
 and the Bakken Formation.
Since October 2011, Enbridge also announced several complementary Eastern Access
and Mainline Expansion Projects, which had various in-service dates throughout
2015. Two of these projects include reversal of Enbridge's Line 9B from
Westover, 
Ontario
 to 
Montreal, Quebec
, to serve refineries in 
Quebec
, and an
expansion of Enbridge's Line 9 to provide additional delivery capacity within
Ontario
 and 
Quebec
.

The Line 9B reversal and Line 9 capacity expansion projects were approved by the
Canadian National Energy Board, or NEB, in March 2014 subject to 30 conditions.
In October 2014, the NEB requested additional information regarding one of the
conditions imposed on the Line 9B reversal and Line 9 expansion project. On
October 23, 2014, Enbridge responded to the NEB describing Enbridge's rigorous
approach to risk management and isolation valve placement. On February 6, 2015,
the NEB approved conditions 16 and 18, the two conditions in the NEB's order
requiring approval, and Enbridge filed for the Leave to Open, or LTO, which is
also a prerequisite to allowing the operation of the project. In its February
approval, the NEB also imposed additional obligations on Enbridge that directs
it to take a "life-cycle" approach to water crossings and valves, requiring
Enbridge to perform ongoing analysis to ensure optimal protection of the area's
water resources. On June 18, 2015, the NEB approved the LTO application and
issued a separate order imposing further conditions requiring Enbridge to
perform hydrostatic tests of selected segments of the pipeline. Enbridge filed
its hydrostatic test plan with the NEB on July 23, 2015, which was approved on
July 27, 2015. Hydrostatic testing was completed and Enbridge submitted the test
results to the NEB in September 2015. On September 30, 2015, the NEB confirmed
that the hydrostatic tests successfully met their criteria. Line fill commenced
in late October 2015 and the pipeline was placed into service in December 2015.

Enbridge Market Extensions

One of our key strengths is our relationship with Enbridge. In 2014, Enbridge
announced the completion of two major U.S. Gulf Coast market access pipeline
projects, the Flanagan South Pipeline and Seaway Crude Pipeline, which pull more
volume through our pipelines and may lead to further expansions of our Lakehead
pipeline system. In 2012, Enbridge announced the Southern Access Extension,
which, along with the reversal of Line 9A and Line 9B, will support the
increasing supply of light oil from 
Canada
 and the Bakken into 
Patoka, Illinois
.

Southern Access Extension

The Southern Access Extension project involves the construction of a 165-mile,
24-inch diameter crude oil pipeline from 
Flanagan
 to 
Patoka, Illinois
, with an
initial capacity of 300,000 Bpd, as well as additional tankage and two new pump
stations. The project was placed into service in December 2015. Lincoln Pipeline
LLC, or Lincoln, an affiliate of MPC, has a 35% equity interest in the project
and will make additional cash contributions in accordance with the Southern
Access Extension's spend profile in proportion to its 35% interest.

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Natural Gas

Our Natural Gas segment includes the operations of our Anadarko, 
East Texas
,
North Texas
, and Texas Express NGL systems, as well as our trucking and
marketing operations. For a detailed description of each of these systems, refer
to Part I, Item I. Business. The following tables set forth the operating
results of our Natural Gas segment and the approximate average daily volumes of
natural gas throughput and NGLs produced on our systems for the years ended
December 31, 2015, 2014 and 2013.

[[Image Removed]]           [[Image Removed]]     [[Image Removed]]     [[Image Removed]]
                                                     December 31,
                                   2015                  2014                  2013
                                                     (in millions)
Operating results:
Operating revenues          $        2,842.7      $         5,894.3     $        5,597.2
Commodity costs                      2,372.9                5,145.9              4,948.9
Segment gross margin                   469.8                  748.4                648.3
Operating expenses:
Operating and
administrative                         351.0                  423.0                449.8
Goodwill impairment                    246.7                      -                    -
Asset impairment                        12.3                   15.6                    -
Depreciation and
amortization                           157.8                  151.4                143.1
Operating expenses                     767.8                  590.0                592.9
Operating income (loss)               (298.0 )                158.4                 55.4
Other income (loss)                     29.3                   13.2                 (1.5 )
Net income (loss)           $         (268.7 )    $           171.6     $           53.9
Operating Statistics
(MMBtu/d):
East Texas                           964,000              1,030,000            1,153,000
Anadarko                             773,000                827,000              949,000
North Texas                          265,000                293,000              317,000
Total                              2,002,000              2,150,000            2,419,000
NGL Production (Bpd)                  81,632                 83,675               88,236

Year ended December 31, 2015, compared with year ended December 31, 2014

The operating income of our natural gas business for the year ended December 31,
2015, decreased $456.4 million, as compared with the year ended December 31,
2014, in part due to a $246.7 million goodwill impairment charge. We performed a
goodwill impairment analysis after we learned from customers during the second
quarter of 2015 that reductions in drilling will be prolonged in the producing
basins in which we operate due to the continued low commodity price environment.
As a result of this analysis, we determined that $246.7 million in goodwill was
impaired.

Decreases in "Operating revenues" and "Cost of natural gas and natural gas
liquids" for the year ended December 31, 2015, as compared with the same period
in 2014, are primarily due to decreases in commodity prices and the resulting
decreased volumes from lower drilling activities. Segment gross margin, which
decreased $278.6 for the year ended December 31, 2015, as compared with the year
ended December 31, 2014, due to the following reasons:

Segment gross margin experienced a net decrease of $216.8 million, due to
non-cash, mark-to-market losses of $58.3 million for the year ended December 31,
2015, including $1.6 million of gains associated with the assignments of certain
natural gas contracts, as compared to gains of $158.5 million for year ended
December 31, 2014. The decrease is primarily the result of a reclassification of
previously recognized unrealized mark-to-market net gains where the underlying
transactions were settled, coupled with decreased non-cash, mark-to-market net
gains due to smaller decreases in average forward prices during 2015 than in
2014.

Segment gross margin decreased $28.0 million for the year ended December 31,
2015, as compared with the same period in December 31, 2014, due to decreased
margins from lower commodity prices, net of hedges, related to contracts where
we were paid in commodities for our services.

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Our segment gross margin was also impacted by decreased margins within our
marketing function due to natural gas pricing differentials between market
centers by approximately $9.7 million for the year ended December 31, 2015, as
compared to the year ended December 31, 2014. During the first quarter of 2014,
we benefited from the difference between market centers in the Mid-Continent
supply areas and market area in the Midwest which arose due to higher than usual
demand from winter weather conditions in the Midwest.

Segment gross margin was affected by reduced production volumes which negatively
affected segment gross margin by approximately $28.7 million for the year ended
December 31, 2015, as compared to the year ended December 31, 2014. The average
daily volumes of our major systems for the year ended December 31, 2015,
decreased by approximately 148,000 million British thermal units per day, or
MMBtu/d, or 7% when compared to the year ended December 31, 2014. The average
NGL production for the year ended December 31, 2015, decreased by 2,043 Bpd, or
2%, when compared to the year ended December 31, 2014. The decrease in natural
gas and NGL volumes was primarily attributable to the continued low commodity
price environment for natural gas, NGLs and condensate, which has resulted in
reductions in drilling activity from producers in the areas we operate.

Our segment gross margin also decreased $9.3 million for the year ended December
31, 2015, as compared with the same period in December 31, 2014. On September 1,
2015, two wholly-owned subsidiaries of Midcoast Operating in the Natural Gas
segment sold certain natural gas inventories and assigned certain storage
agreements, transportation contracts and other arrangements to a third party. We
recognized a loss of $9.3 million in connection with this transaction, primarily
related to costs to transfer certain fixed-demand storage and transportation
obligations to the buyer.

Our segment gross margin decreased $8.0 million for the year ended December 31,
2015, as compared with the same period in 2014, due to lower storage margins as
a result of the relative difference between the injection price paid to purchase
and store natural gas, crude oil and NGLs and the withdrawal price at which
these commodities are sold from storage.

Segment gross margin increased $7.4 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to decreased physical measurement losses as a result of system efficiencies. Physical measurement gains and losses routinely occur on our systems as part of our normal operations, which result from evaporation, shrinkage, differences in measurement between receipt and delivery locations and other operational conditions

Our segment gross margin also increased $5.6 million for year ended December 31, 2015, when compared to the same period of 2014, for decreases in non-cash charges to decrease the cost basis of our natural gas inventory to net realizable value recorded in 2014.

Operating and administrative costs decreased $72.0 million for the year ended
December 31, 2015, when compared to the year ended December 31, 2014 primarily
due to cost reduction efforts undertaken by management, including $15.0 million
in workforce reductions, which resulted in a decrease in contract labor as well
as other related cost benefits. In addition, other cost reduction efforts have
resulted in reduced repairs and maintenance costs.

Depreciation and amortization expense increased $6.4 million, for the year ended December 31, 2015, compared with the year ended December 31, 2014, due to additional assets that were placed into service.

Other income increased $16.1 million for the year ended December 31, 2015, compared with the year ended December 31, 2014, primarily due to increases in equity earnings on our investment in the Texas Express NGL system. These increases were a result of higher volumes and increases in ship-or-pay commitments during 2015.

Year ended December 31, 2014, compared with year ended December 31, 2013

The operating income of our Natural Gas segment for the year ended December 31,
2014, increased $103.0 million, as compared with the year ended December 31,
2013. The most significant area affected was segment gross margin, representing
revenue less commodity costs, which increased $100.1 million for the year ended
December 31, 2014, as compared with the year ended December 31, 2013.

Segment gross margin experienced an increase in non-cash, mark-to-market net
gains of $161.5 million for the year ended December 31, 2014, compared to the
year ended December 31, 2013, primarily related to non-cash, mark-to-market
gains in the year ended December 31, 2014, on our NGL hedges. The values of
these hedges and contracts, which help assure the prices we realize on
commodities, increased as the related physical commodity value decreased.

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Segment gross margin increased $15.6 million for the year ended December 31,
2014, as compared to the year ended December 31, 2013 due to increased margins
from natural gas pricing differentials in the first quarter of 2014. We
benefited from the difference between market centers in the Mid-Continent supply
areas and market area in the Midwest, which arose from higher than normal demand
from winter weather in the Midwest.

Segment gross margin increased $2.3 million for the year ended December 31, 2014, due to improved pricing spreads between our

Conway
and
Mont Belvieu
market hubs when compared with the year ended December 31, 2013.
Segment gross margin was affected by reduced production volumes which negatively
affected segment gross margin by approximately $45.8 million for the year ended
December 31, 2014, as compared to the year ended December 31, 2013. The average
daily volumes of our major systems for the year ended December 31, 2014,
decreased by approximately 269,000 million British thermal units per day, or
MMBtu/d, or 11% when compared to the year ended December 31, 2013. The average
NGL production for the year ended December 31, 2014, decreased by 4,561 Bpd, or
5%, when compared to the year ended December 31, 2013. The decrease in natural
gas and NGL volumes in the Anadarko region was primarily attributable to the
loss in 2013 of a major customer on our Anadarko system and delayed drilling
activity by certain producers. The decrease in natural gas volumes in the 
East Texas
 region was primarily attributable to reduced dry gas drilling, and delayed
drilling activity and well completions.

Segment gross margin derived from keep-whole earnings for the year ended
December 31, 2014, decreased $33.4 million when compared to the year ended
December 31, 2013, due to a decrease in processing margins primarily driven by
lower volumes in keep-whole barrels in the 
Oklahoma
, 
East Texas
, and Anadarko
regions.

Segment gross margin decreased approximately $3.0 million for the year ended
December 31, 2014, primarily due to the impact of sustained freezing
temperatures in the first quarter 2014, which significantly disrupted producer
wellhead production levels and our pipeline operations compared to the year
ended December 31, 2013.

Operating and administrative costs decreased $26.8 million for the year ended
December 31, 2014, when compared to the year ended December 31, 2013 primarily
related to reduced outside contract labor, and lower rents and leases. This
decrease was offset by an increase in costs from a non-cash impairment on our
non-core 
Louisiana
 propylene pipeline asset of $15.6 million. The impairment
charge was taken following finalization of a contract restructuring with the
primary customer. In addition, in December of 2014, the company took actions to
reduce its costs through a workforce reduction, which increased severance costs
by $4.8 million for the year ended December 31, 2014, as compared to the year
ended December 31, 2013.

Depreciation and amortization expense increased $8.3 million, for the year ended December 31, 2014, compared with the year ended December 31, 2013, due to additional assets that were placed into service.

We recognized $13.2 million in equity income in "Other income (expense)" on our
consolidated statements of income related to our investment in the Texas Express
NGL system. This is due to a full year of operations of the pipeline which went
into service in November 2013.

Future Prospects for Natural Gas

We intend to expand our natural gas gathering and processing services by: (1)
capturing opportunities within our footprint, (2) expanding outside of our
footprint through strategic acquisitions, (3) providing an array of services for
both natural gas and NGLs in combination with core asset optimization, and (4)
capitalizing on new market opportunities by diversifying geographically and by
commodity composition. We will pursue internal growth projects designed to
provide exposure to incremental supplies of natural gas at the wellhead,
increase opportunities to serve additional customers, including new wholesale
customers, and allow expansion of our treating and processing businesses.
Additionally, we will pursue acquisitions to expand our natural gas business in
situations where we have competitive advantages to create additional value.

Impact of Commodity Prices

Demand for our midstream services primarily depends upon the supply of natural
gas and associated natural gas from crude oil development and the drilling rate
for new wells. Demand for these services depends on overall economic conditions
and commodity prices. Commodity prices for natural gas, NGLs, condensate and
crude oil have remained low throughout 2015. The depressed commodity price
environment is the most significant factor for reduced drilling activity and
declining volumes in the basins in which we operate. We expect producers to
continue to reduce drilling activity due to the current commodity price
environment, and as a result, we expect to see a

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decrease in volumes in 2016. We factored these expected decreases into our fixed
asset and intangible asset recoverability tests on our Anadarko, 
North Texas
,
and 
East Texas
 assets during 2015 and do not expect any impairment on these
assets at this time. However, further declines in long-term volumes or reserves
could affect our assessments.

We have largely mitigated our near-term direct commodity price risk through our
hedging program. We have hedged approximately 90% and 40% of our direct
forecasted commodity cash flow exposure for 2016 and 2017, respectively. Despite
our hedging program, we still bear indirect commodity price exposure as lower
drilling activity impacts the volumes on our systems as well as direct commodity
price exposure for unhedged commodity positions. We expect this indirect impact
on our volumes to improve as prices improve.

Expansion Projects

The following expansion projects are designed to increase natural gas
processing, NGL production, residue gas and NGL transportation capacity. The
paragraphs below summarize our projects that we have placed into service in 2015
or expect to place into service in future periods.

Beckville Cryogenic Processing Plant

In May 2015, we placed into service a cryogenic natural gas processing plant
near 
Beckville
 in 
Panola County, Texas
, which we refer to as the 
Beckville
Processing Plant. This plant serves existing and prospective customers pursuing
production in the 
Cotton Valley
 formation, which is comprised of approximately
ten counties in 
East Texas
 and has been a steady producer of natural gas for
decades, as well as the Eaglebine developments. Production from the 
Cotton Valley
 formation typically contains two to three gallons of NGLs per Mcf of
natural gas. Our 
Beckville
 processing plant is capable of processing
approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of
NGLs to accommodate the additional liquids-rich natural gas being developed
within this geographical area in which our 
East Texas
 system operates. Related
NGL takeaway infrastructure connecting the 
Beckville
 plant to third party NGL
transportation systems was also constructed. This project cost approximately
$165.0 million.

The project was funded by us and MEP based on our proportionate ownership percentages in Midcoast Operating, which are 48.4% and 51.6%, respectively.

Eaglebine Developments

The Eaglebine is an emerging oil play in 
East Texas
 that spans over five
counties and is comprised of multiple formations, including but not limited to,
the Woodbine, 
Buda
, Glenrose and Eagle Ford formations. We have a series of
construction projects and an acquisition in this play. We have completed
construction of the Ghost Chili pipeline project, which consists of a lateral
and associated facilities that create gathering capacity of over 50 MMcf/d for
rich natural gas to be delivered from Eaglebine production areas to our complex
of cryogenic processing facilities in 
East Texas
. The initial facilities were
placed into service in October 2015. We also expect to construct the Ghost Chili
Extension Lateral to fully utilize this gathering capacity with the rest of our
processing assets when additional development in the basin supports it. Given
the proximity of our existing 
East Texas
 assets, this expansion into Eaglebine
will allow us to offer gathering and processing services while leveraging assets
on our existing footprint.

On February 27, 2015, we acquired from New Gulf Resources, LLC, or NGR, its
midstream operations in 
Leon
, 
Madison
 and 
Grimes
 counties, 
Texas
. The
acquisition consists of a natural gas gathering system currently in operation.
For further details regarding the NGR acquisition, refer to Item 8. Financial
Statements and Supplementary Data, Note 4. Acquisitions.

We estimate the aggregate cost of our Eaglebine projects and acquisition
described above to be approximately $160.0 million, of which $116.8 million was
spent in 2015. Remaining funding is to be provided by us and MEP based on our
proportionate ownership percentages in Midcoast Operating, subject to market
conditions and our financing capacity.

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Corporate

Our corporate results consist of interest expense, interest income, allowance
for equity during construction and other costs such as income taxes, which are
not allocated to the business segments.

[[Image Removed]]        [[Image Removed]]      [[Image Removed]]      [[Image Removed]]
                                                    December 31,
                                 2015                   2014                   2013
                                                   (in millions)
Operating Results:
Operating and
administrative
expenses                 $          14.4        $          10.6        $           7.6
Operating loss                     (14.4 )                (10.6 )                 (7.6 )
Interest expense, net             (322.0 )               (403.2 )               (320.4 )
Allowance for equity
used during
construction                        70.3                   57.2                   43.1
Other income (expense)                 -                   (4.3 )                 17.5
Income (loss) before
income tax expense                (266.1 )               (360.9 )               (267.4 )
Income tax expense                  (4.9 )                 (9.6 )                (18.7 )
Net loss                 $        (271.0 )      $        (370.5 )      $        (286.1 )

Year ended December 31, 2015 compared with year ended December 31, 2014

The $99.5 million decrease in our net loss for the year ended December 31, 2015,
as compared to the same period in 2014 was primarily attributable to a decrease
in interest expense.

Interest expense decreased $81.2 million for the year ended December 31, 2015,
when compared with the year ended December 31, 2014, primarily due to a decrease
in the recognition of the ineffective portion of unrealized and realized losses
on our pre-issuance hedges. In 2014, we recognized $100.6 million in interest
expense for hedge ineffectiveness from extending the maturity dates of our
pre-issuance hedges that were set to mature in 2014. In October 2015, we settled
some of these pre-issuance hedges. This decrease period over period was offset
by higher interest cost on newly-issued senior debt.

Year ended December 31, 2014 compared with year ended December 31, 2013

The increase in our net loss in 2014 was primarily due to an increase in
interest expense to $403.2 million for the year ended December 31, 2014,
compared with $320.4 million for the corresponding period in 2013. This increase
in interest expense is primarily due to an increase of approximately $1.9
billion in our outstanding debt balance. Also contributing to the increase in
interest expense is the recognition of unrealized losses for hedge
ineffectiveness of approximately $100.1 million.

Income tax expense decreased $9.1 million for the year ended 2014 compared to
the same period in 2013, primarily due to a tax law that was passed in June 2013
in the 
State of Texas
, referred to as House Bill 500, or HB 500. The law allows
a pipeline company that transports oil, gas, or other petroleum products owned
by others to subtract as COGS, its depreciation, operations and maintenance
costs related to the services provided. Under the new law, we are allowed
additional deductions against our income for 
Texas
 margin tax purposes.

LIQUIDITY AND CAPITAL RESOURCES
General

Our primary operating cash requirements consist of normal operating expenses,
maintenance capital expenditures, funding requirements associated with
environmental costs, distributions to our partners and payments associated with
our risk management activities. We expect to fund our current and future
short-term cash requirements for these items from our operating cash flows
supplemented as necessary by issuances of commercial paper and borrowings under
our Credit Facilities. Margin requirements associated with our derivative
transactions are generally supported by letters of credit issued under our
Credit Facilities.

Our current business strategy emphasizes developing and expanding our existing
Liquids and Natural Gas businesses through organic growth and targeted
acquisitions. We expect to initially fund our long-term cash requirements for
expansion projects and acquisitions, as well as retire our maturing and callable
debt, first from operating cash flows and then from issuances of commercial
paper and borrowings on our Credit Facilities. We expect to obtain permanent
financing as needed through the issuance of additional equity and debt
securities, which we will use to repay amounts initially drawn to fund these
activities, although there can be no assurance that such

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financings will be available on favorable terms, if at all. In addition, we
intend to sell additional interests in Midcoast Operating to MEP to raise
capital over the course of the next several years. Although this is our intent,
there is no assurance that any transactions will occur as they are subject to,
among other things, obtaining agreement from MEP and the board of directors of
its general partner on the commercial terms of such a sale. In the past, when we
had attractive growth opportunities in excess of our own capital raising
capabilities, the General Partner provided supplementary funding, or
participated directly in projects, to enable us to undertake such opportunities.
If in the future we have attractive growth opportunities that exceed capital
raising capabilities, we could seek similar arrangements from the General
Partner, but there can be no assurance that this funding can be obtained.

Available Liquidity

Our primary source of short-term liquidity is provided by our $1.5 billion
commercial paper program, which is supported by our $1.975 billion multi-year
unsecured revolving credit facility, which we refer to as the Credit Facility,
and our $625.0 million credit agreement, which we refer to as the 364-Day Credit
Facility. We access our $1.5 billion commercial paper program primarily to
provide temporary financing for our operating activities, capital expenditures
and acquisitions when the interest rates available to us for commercial paper
are more favorable than the rates available under our Credit Facilities.

As set forth in the following table, we had approximately $1.5 billion of liquidity available to us at December 31, 2015, to meet our ongoing operational, investment and financial needs.

[[Image Removed]]                              [[Image Removed]]     [[Image Removed]]
                                                       EEP                   MEP
                                                             (in millions)
Cash and cash equivalents                      $           130.1     $            18.0
Total credit available under our Credit
Facilities                                               2,600.0            

-

Total credit available under MEP's Credit
Agreement                                                      -            

810.0

Less: Amounts outstanding under our Credit
Facilities                                               1,110.0            

-

Less: Amounts outstanding under MEP's Credit
Agreement                                                      -            

490.0

 Principal amount of commercial paper
issuances                                                  326.1            

-

 Letters of credit outstanding                             121.7                     -
Total                                          $         1,172.3     $           338.0


As of December 31, 2015, although we had a working capital deficit of
approximately $1.0 billion, we had approximately $1.5 billion of liquidity to
meet our ongoing operational, investing and financing needs as described above,
as well as the funding requirements associated with the environmental
remediation costs resulting from the crude oil releases on Line 6B.

Capital Resources
Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction
projects contemplate our accessing the public and private equity and credit
markets to obtain the capital necessary to fund these activities. We have issued
a balanced combination of debt and equity securities to fund our expansion
projects and acquisitions. Our internal growth projects and targeted
acquisitions will require additional permanent capital and require us to bear
the cost of constructing and acquiring assets before we begin to realize a
return on them. If market conditions change and capital markets become
constrained, our ability and willingness to complete future debt and equity
offerings may be limited, which in turn, could affect our ability to execute our
growth strategy or complete our planned construction projects. The timing of any
future debt and equity offerings will depend on various factors, including
prevailing market conditions, interest rates, our financial condition and our
credit rating at the time.

From time to time, we may seek to satisfy liquidity needs through the issuance
of registered debt or equity securities. In February 2015, we filed with the SEC
a new shelf registration statement, or the 2015 Shelf, on Form S-3 that replaced
our prior shelf registration statement which expired in December 2014. The 2015
Shelf allows us to issue an unlimited amount of equity and debt securities in
underwritten public offerings.

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Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit
issuances for the year ended December 31, 2015. The proceeds from the March 2015
offering were used to fund a portion of our capital expansion projects and for
general partnership purposes. There were no issuances of Class A common units
for the years ended December 31, 2014 and 2013.

[[Image Removed]]    [[Image Removed]]     [[Image Removed]]     [[Image Removed]]     [[Image Removed]]             [[Image Removed]]
                          Number of                                                                                     Net Proceeds
                           Class A           Offering Price         Net Proceeds                                          Including
                        common units           per Class A             to the                General Partner           General Partner
2015 Issuance Date         Issued              common unit         Partnership(1)            Contribution(2)            Contribution
                                                      (in millions, except units and per unit amounts)
March                        8,000,000     $           36.70     $           288.8     $               6.0           $           294.8


[[Image Removed]]

(1) Net of underwriters' fees and discounts, commissions and issuance expenses.

(2) Contributions made by the General Partner to maintain its 2% general partner

      interest.


Series 1 Preferred Units

In 2013, we issued and sold 48,000,000 Series 1 preferred units, representing
limited partner interests in us, or Preferred Units, for aggregate proceeds of
approximately $1.2 billion. We used proceeds from the Preferred Unit issuance to
repay commercial paper, to finance a portion of our capital expansion program
relating to our core liquids and natural gas systems and for general partnership
purposes. On July 30, 2015, we amended our limited partnership agreement to
extend the deferral of distribution payments, to extend the rate reset pricing
date, and to defer the conversion option date, as discussed below.

The Preferred Units are entitled to annual cash distributions of 7.50% of the
issue price, payable quarterly, which are subject to reset on June 30, 2020, and
each subsequent five-year anniversary thereafter. However, these quarterly cash
distributions, during the first full twenty quarters ending June 30, 2018, will
accrue and accumulate, which we refer to as the Payment Deferral. These amounts
will be paid in equal amounts over a twelve-quarter period beginning in the
first quarter of 2019.

On or after June 1, 2018, at the sole option of the holder of the Preferred
Units, the Preferred Units may be converted into Class A Common Units, in whole
or in part, at a conversion price of $27.78 per unit plus any accrued,
accumulated and unpaid distributions, excluding the Payment Deferral, as
adjusted for splits, combinations and unit distributions. For further details
regarding the Preferred Units, refer to Item 8. Financial Statements and
Supplementary Data, Note 11. Partners' Capital.

Midcoast Energy Partner, L.P.

In 2013, MEP completed the Offering of 21,725,000 Class A common units
representing limited partner interests, including the underwriter's over
allotment option. MEP received proceeds (net of underwriting discounts,
structuring fees and offering expenses) from the Offering of approximately
$354.9 million. MEP used the net proceeds to distribute approximately $304.5
million to us, to pay approximately $3.4 million in revolving credit facility
origination and commitment fees and used approximately $47.0 million to redeem
2,775,000 Class A common units from us.

On July 1, 2014, we sold a 12.6% limited partner interest in Midcoast Operating
to MEP, for $350.0 million in cash, which reduced our total ownership interest
in Midcoast Operating from 61% to 48.4%. This transaction represents our first
sale to MEP of additional interests in Midcoast Operating since the Offering.

At December 31, 2015, we owned 5.9% of outstanding MEP Class A common units,
100% of the outstanding MEP Subordinated Units, 100% of MEP's general partner
and 48.4% of the limited partner interests in Midcoast Operating. We intend to
sell additional interests in our natural gas assets, held through Midcoast
Operating, to MEP and use the proceeds from any such sale as a source of funding
for us. However, we do not know when, or if, any additional interests will be
offered for sale.

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Investments

In March and September 2013, Enbridge Management completed public offerings of
10,350,000 and 8,424,686 Listed Shares, respectively, representing limited
liability company interests with limited voting rights for net proceeds of
$272.9 million and $235.6 million, respectively, Enbridge Management used those
proceeds to purchase an equal number of the Partnership's i-units. We used the
proceeds from our sale of i-units to Enbridge Management to finance a portion of
our capital expansion program relating to the expansion of our core liquids and
natural gas systems and for general corporate purposes.

Credit Facilities

The Credit Facility, permits aggregate borrowings of up to, at any one time
outstanding, $1.975 billion, a letter of credit subfacility and a swing line
subfacility. The Credit Facility matures September 26, 2020; however, $175.0
million of commitments will expire on the original maturity date of September
26, 2018.

The 364-Day Credit Facility is a committed senior unsecured revolving credit
facility that permits aggregate borrowings of up to, at any one time
outstanding, $625.0 million subject to the terms and conditions set forth
therein. The 364-Day Credit Facility provides aggregate lending commitments: (1)
on a revolving basis for a 364-day period, extendible annually at the lenders'
discretion, and (2) for a 364-day term on a non-revolving basis following the
expiration of all revolving periods, which is currently July 1, 2016.

At December 31, 2015, the Credit Facilities provide an aggregate bank credit amount of approximately $2.6 billion, which we use to fund our general activities and working capital needs.

On November 16, 2015, we received a commitment reduction notice from Enbridge
(U.S.) Inc., or EUS, an affiliate of Enbridge, with respect to the credit
agreement with EUS, or the EUS 364-day Credit Facility, that previously
permitted aggregate borrowing of up to, at any one time outstanding, $750.0
million. EUS elected to reduce its commitment to zero following the
Partnership's offering of $1.6 billion of debt securities in October of 2015.
See Note 9. Related Party Transactions for further details.

As of December 31, 2015, we were in compliance with the terms of all of our
financial covenants under the Credit Facilities. For further details regarding
the Credit Facilities and the amendments thereto, refer to Item 8. Financial
Statements and Supplementary Data, Note 10. Debt.

We are party to an uncommitted letter of credit arrangement, pursuant to which
the bank may, on a discretionary basis and with no commitment, agree to issue
standby letters of credit upon our request in an aggregate amount not to exceed
$175.0 million. While the letter of credit arrangement is uncommitted and
issuance of letters of credit is at the bank's sole discretion, we view this
arrangement as liquidity enhancement as it allows us to potentially reduce our
reliance on utilizing the committed Credit Facilities for issuance of letters of
credit to support our hedging activities.

Commercial Paper

We are party to a commercial paper program that provides for the issuance of up
to an aggregate principal amount of $1.5 billion of commercial paper and is
supported by our Credit Facilities. We access the commercial paper market
primarily to provide temporary financing for our operating activities, capital
expenditures and acquisitions when the available interest rates we can obtain
are lower than the rates available under our Credit Facilities. At December 31,
2015, we had $326.1 million in principal amount of commercial paper outstanding
at a weighted average interest rate of 1.22%, excluding the effect of our
interest rate hedging activities. Under our commercial paper program, we had net
repayments of approximately $286.1 million during the year ended December 31,
2015, which includes gross borrowings of $12.0 billion and gross repayments of
$12.3 billion. At December 31, 2014, we had $612.3 million in principal amount
of commercial paper outstanding at a weighted average interest rate of 0.50%,
excluding the effect of our interest rate hedging activities. Our policy is that
the commercial paper we can issue is limited by the amounts available under our
Credit Facility up to an aggregate principal amount of $1.5 billion. For further
details regarding the commercial paper program, refer to Item 8. Financial
Statements and Supplementary Data, Note 10. Debt.

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The amounts we may borrow under the terms of our Credit Facilities are reduced
by the face amount of our letters of credit outstanding. It is our policy to
maintain availability at any time under our Credit Facilities amounts that are
at least equal to the amount of commercial paper that we have outstanding at
such time. Taking that policy into account, at December 31, 2015, we could
borrow approximately $1.0 billion under the terms of our Credit Facilities,
determined as follows:

[[Image Removed]]                                       [[Image Removed]]
                                                           (in millions)

Total credit available under our Credit Facilities $ 2,600.0 Less: Amounts outstanding under our Credit Facilities

             1,110.0
 Principal amount of commercial paper outstanding                   326.1
 Letters of credit outstanding                                      121.7
Total amount available at December 31, 2015             $         1,042.2


Senior Notes

On October 6, 2015, we closed a public offering of $1.6 billion of senior unsecured notes, comprised of $500 million aggregate principal amount of notes due October 15, 2020, $500 million aggregate principal amount of notes due October 15, 2025 and $600 million aggregate principal amount of notes due October 15, 2045 for net proceeds of approximately $1.575 billion after deducting underwriting discounts and commissions and estimated offering expenses. For further details regarding the senior notes, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

Our senior notes represent our unsecured obligations that rank equally in right
of payment with all of our existing and future unsecured and unsubordinated
indebtedness. Our senior notes are structurally subordinated to all existing and
future indebtedness and other liabilities, including trade payables of our
subsidiaries and the $200.0 million of senior notes issued by the OLP, which we
refer to as the OLP Notes. The OLP, our operating subsidiary that owns the
Lakehead system, has $200.0 million of senior notes outstanding representing
unsecured obligations that are structurally senior to our senior notes. The OLP
Notes consist of $100.0 million of 7.000% senior notes due 2018 and $100.0
million of 7.125% senior notes due 2028. All of the OLP Notes pay interest
semi-annually.

For further details regarding the OLP Notes, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

Junior Subordinated Notes

The $400.0 million in principal amount of our fixed/floating rate, junior
subordinated notes due October 1, 2067, which we refer to as the Junior Notes,
represent our unsecured obligations that are subordinate in right of payment to
all of our existing and future senior indebtedness. The Junior Notes bear
interest at a fixed annual rate of 8.05%, exclusive of any discounts or interest
rate hedging activities, payable semi-annually in arrears on April 1 and October
1 of each year until October 1, 2017. After October 1, 2017, the Junior Notes
will bear interest at a variable rate equal to the three-month London Interbank
Offered Rate, or LIBOR, for the related interest period increased by 3.7975%,
payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each
year beginning January 1, 2018. For further details regarding the junior
subordinated notes, refer to Item 8. Financial Statements and Supplementary
Data, Note 10. Debt.

MEP Credit Agreement

MEP, Midcoast Operating, and MEP's material domestic subsidiaries are parties to
the MEP Credit Agreement, which is a committed syndicated senior revolving
credit facility with related letter of credit and swing line facilities. On
September 3, 2015, MEP amended its Credit Agreement to decrease the aggregate
commitments to $810.0 million and extend the maturity date from September 30,
2017 to September 30, 2018; however, $140.0 million of commitments will expire
on the initial maturity date of November 13, 2016 and an additional $25.0
million of commitments will expire on September 30, 2017.

The MEP Credit Agreement also requires compliance with two financial covenants.
MEP is not permitted to allow their ratio of consolidated funded debt to pro
forma EBITDA (the total leverage ratio), as of the end of any applicable
four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition
periods. MEP must also maintain (on a consolidated basis), as of the end of each
applicable four-quarter period, a ratio of pro forma EBITDA to consolidated
interest expense for such four-quarter period then ended of at least 2.50 to
1.00. These covenants could limit MEP's ability to undertake additional debt
financing.

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At December, 31, 2015, MEP was in compliance with the terms of our financial
covenants in the Credit Agreement. Due to the continued decline in oil and gas
prices and the potential implications on their results of operations, it is
possible that MEP may not be able to meet the total leverage ratio financial
covenant at some point during the remaining term of the facility. If this were
to occur, MEP would seek a waiver from its lenders, seek additional capital
contributions, pursue refinancing of the amounts outstanding under the Credit
Agreement or seek to take other action to prevent a default under the Credit
Agreement, although there is no assurance that MEP could obtain any such
necessary preventative actions. Failure to comply with one or both of the
financial covenants may result in the occurrence of an event of default under
the Credit Agreement, which would result in a cross-default under the note
purchase agreement on the Notes. If an event of default were to occur, the
lenders could, among other things, terminate their commitments under the Credit
Agreement, demand immediate payment of all amounts borrowed by MEP and Midcoast
Operating, trigger the springing liens, and require adequate security or
collateral for all outstanding letters of credit outstanding under the facility.

At December 31, 2015, MEP had $490.0 million in outstanding borrowings under the
MEP Credit Agreement at a weighted average interest rate of 3.71%. Under the MEP
Credit Agreement, MEP had net borrowings of approximately $130.0 million during
the year ended December 31, 2015, which includes gross borrowings of $6.1
billion and gross repayments of $6.0 billion. At December, 31, 2015, MEP was in
compliance with the terms of its financial covenants in the MEP Credit
Agreement. For further details regarding the MEP Credit Agreement and the
amendments thereto, refer to Item 8. Financial Statements and Supplementary
Data, under Note 10. Debt.

MEP Private Debt Issuance

In 2014, MEP completed a private offering of $400.0 million of notes consisting
of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes
due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and
$150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the
Notes. All of the Notes pay interest semi-annually on March 31 and September 30,
commencing on March 31, 2015.

The purchase agreement related to the Notes also requires compliance with two
financial covenants. We must not permit the ratio of consolidated funded debt to
pro forma EBITDA (the total leverage ratio), as of the end of any applicable
four quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition
periods. We also must maintain, on a consolidated basis, as of the end of each
applicable four-quarter period, a ratio of pro forma EBITDA to consolidated
interest expense for such four quarter period then ended of at least 2.50 to
1.00.

At December 31, 2015, we were in compliance with the terms of our financial
covenants under the Notes and the related purchase agreement. Due to the
continued decline in oil and gas prices and the potential implications on our
results of operations, it is possible that we may not be able to meet the total
leverage ratio financial covenant at some point during the remaining term of the
facility. If this were to occur, we would seek a waiver from the note holders,
seek additional capital contributions, pursue refinancing of the amounts
outstanding under the Notes or seek to take other action to prevent a default
under the purchase agreement and the Notes, although there is no assurance that
we could obtain any such necessary preventative actions. Any failure to comply
with one or both of the financial covenants could result in the occurrence of an
event of default under the purchase agreement and the Notes and result in a
cross-default under the Credit Agreement. If an event of default were to occur,
the note holders could, among other things, demand immediate payment of the
Notes and trigger the springing liens.

For further details about the Notes and related private placement, refer to Item 8. Financial Statements and Supplementary Data, under Note 10. Debt.

Maturities of Third Party Debt

The scheduled maturities of outstanding third-party debt, excluding any discounts at December 31, 2015, are summarized as follows in millions:

[[Image Removed]]   [[Image Removed]]
2016                            300.0
2017                            826.1
2018                            990.0
2019                            575.0
2020                $         1,610.0
Thereafter                    3,775.0
Total               $         8,076.1


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Joint Funding Arrangements

In order to obtain the required capital to expand our various pipeline systems,
we have determined that the required funding would challenge our ability to
efficiently raise capital. Accordingly, we have explored numerous options and
determined that several joint funding arrangements would provide the best source
of available capital to fund the expansion projects.

Joint Funding Arrangement for Alberta Clipper Pipeline

Until January 2, 2015, we had a joint funding arrangement with several of our
affiliates and affiliates of Enbridge to finance the construction of 
the United States
 segment of the Alberta Clipper Pipeline. On January 2, 2015, we completed
the Drop Down transaction pursuant to which the General Partner and its
affiliates contributed to us the remaining 66.7% interest in the 
U.S.
 segment of
the Alberta Clipper Pipeline in exchange for approximately 18,114,975 units of a
new class of limited partner interests designated as Class E units with a fair
value of $767.7 million. As part of the joint funding arrangement, we repaid
borrowings outstanding and payable to our General Partner under a promissory
note, which we referred to as the A1 Term Note.

Amendment of OLP Limited Partnership Agreement

On July 30, 2015, the partners amended and restated the limited partnership
agreement of the OLP, pursuant to which our General Partner will temporarily
forego Series EA and ME, collectively, the Series, distributions commencing in
the quarter ended June 30, 2015, through the quarter ending March 31, 2016. The
General Partner's capital funding contribution requirements for each of those
two Series, commencing in August 2015, will be reduced by the amount of its
foregone cash distributions from the respective Series, until the earlier of
December 31, 2016 and the date aggregate reductions in capital contributions for
such Series are equal to the foregone cash distributions for such Series. To the
extent that the General Partner's portion of capital contributions prior to
December 31, 2016 are insufficient to cover the General Partner's foregone cash
distributions for a Series, beginning with the distribution related to the first
quarter of 2017 for that Series, we will receive reduced cash distributions by
up to 50%, and the General Partner will receive a comparable increase in cash
distributions each quarter until the General Partner has received an aggregate
amount of contribution reductions and distribution increases equal to the amount
of foregone cash distributions.

Joint Funding Arrangement for Eastern Access Projects

We have a joint funding arrangement with the General Partner that establishes an
additional series of partnership interests in the OLP, which we refer to as the
EA interests. The EA interests were created to finance projects to increase
access to refineries in 
the United States
 Upper Midwest and in 
Ontario, Canada
for light crude oil produced in western 
Canada
 and 
the United States
, which we
refer to as the Eastern Access Projects. Our General Partner owns 75% of the EA
interests, and, except as described above in Amendment of OLP Limited
Partnership Agreement, the Eastern Access Projects are jointly funded by our
General Partner at 75% and us at 25%. Within one year of the in-service date,
scheduled for mid-2016, we have the option to increase our economic interest by
up to 15 percentage points. During 2015, the General Partner made equity
contributions of $119.3 million to the OLP to fund its equity portion of the
construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for

U.S.
Mainline Expansion Projects
We have a joint funding arrangement with the General Partner that establishes
another series of partnership interests in the OLP, which we refer to as the ME
interests. The ME interests were created to finance projects to increase access
to the markets of 
North Dakota
 and western 
Canada
 for light oil production on
our Lakehead System between 
Neche, North Dakota
 and 
Superior, Wisconsin
, which
we refer to as our Mainline Expansion Projects. Our General Partner now owns 75%
of the ME interests, and, except as described above in Amendment of OLP Limited
Partnership Agreement, the 
U.S.
 Mainline Expansion Projects are jointly funded
by our General Partner at 75% and us at 25%. Within one year of the in-service
date, currently scheduled for 2016, we have the option to increase our economic
interest held at that time by up to 15 percentage points. During 2015, the
General Partner made equity contributions of $673.3 million to the OLP to fund
its equity portion of the construction costs associated with the 
U.S.
 Mainline
Expansion Projects.

All other operations are captured by the Lakehead interests. For further details
regarding our joint funding arrangements refer to Item 8. Financial Statements
and Supplementary Data, Note 12. Related Party Transactions.

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Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase
agreement, which we refer to as the Receivables Agreement, with an indirect
wholly owned subsidiary of Enbridge. The Receivables Agreement terminates on
December 30, 2016. Pursuant to the Receivables Agreement, the Enbridge
subsidiary will purchase on a monthly basis, for cash, current accounts
receivables and accrued receivables, or the receivables, of certain of our
subsidiaries and certain subsidiaries of MEP that are participating sellers
under the Receivables Agreement, up to an aggregate monthly maximum of $450.0
million, net of receivables that have not been collected.

For the year ended December 31, 2015, we sold and derecognized $3,710.4 million
of receivables to the Enbridge subsidiary, and we received cash proceeds of
$3,709.3 million. As of December 31, 2015, $317.0 million of the receivables
were outstanding and had not been collected on behalf of the Enbridge
subsidiary.

For further details regarding the Receivable Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 12. Related Party Transactions.

Cash Requirements
Capital Spending

We incurred capital expenditures of approximately $2.2 billion for the year
ended December 31, 2015, including $93.2 million of maintenance capital
expenditures and $863.3 million of expenditures that were financed by
contributions from our General Partner and MPC via joint funding arrangements.
In addition, we incurred $4.2 million of contributions to fund our joint
ventures. At December 31, 2015, we had approximately $678.6 million in
outstanding purchase commitments attributable to capital projects for the
construction of assets that will be recorded as property, plant and equipment in
the future.

We categorize our capital expenditures as either maintenance capital or
expansion capital expenditures. Maintenance capital expenditures are those
expenditures that are necessary to maintain the service capability of our
existing assets and include the replacement of system components and equipment
which are worn, obsolete or completing its useful life. We also include in
maintenance capital expenditures a portion of our expenditures for connecting
natural gas wells, or well-connects, to our natural gas gathering systems.
Expenditure levels will increase as pipelines age and require higher levels of
inspection, maintenance and capital replacement. We also anticipate that
maintenance capital will increase due to the growth of our pipeline systems and
the aging of portions of these systems. Maintenance capital expenditures are
expected to be funded by operating cash flows.

Expansion capital expenditures include our capital expansion projects and other
projects that improve the service capability of our existing assets, extend
asset useful lives, increase capacities from existing levels, reduce costs or
enhance revenues and enable us to respond to governmental regulations and
developing industry standards. We anticipate funding expansion capital
expenditures temporarily through borrowing under the terms of our Credit
Facility, with permanent debt and equity funding being obtained when
appropriate.

We maintain a comprehensive integrity management program for our pipeline
systems, which relies on the latest technologies that include internal pipeline
inspection tools. These internal pipeline inspection tools identify internal and
external corrosion, dents, cracking, stress corrosion cracking and combinations
of these conditions. We regularly assess the integrity of our pipelines
utilizing the latest generations of metal loss, caliper and crack detection
internal pipeline inspection tools. We also conduct hydrostatic testing to
determine the integrity of our pipeline systems. Accordingly, we incur
substantial expenditures each year for our integrity management programs. We
expect to incur continuing annual capital and operating expenditures for
pipeline integrity measures to ensure both regulatory compliance and to maintain
the overall integrity of our pipeline systems. Under our capitalization policy,
expenditures that replace major components of property or extend the useful
lives of existing assets are capital in nature, while expenditures to inspect
and test our pipelines are usually considered operating expenses.

Acquisitions

We continue to assess ways to generate value for our unitholders, including
reviewing opportunities that may lead to acquisitions or other strategic
transactions, some of which may be material. We evaluate opportunities against
operational, strategic and financial benchmarks before pursuing them. We expect
to obtain the funds needed to make acquisitions through a combination of cash
flows from operating activities, borrowings under our Credit Facilities and the
issuance of additional debt and equity securities. All acquisitions are
considered in the context of the practical financing constraints presented by
the capital markets.

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Forecasted Expenditures

We estimate our capital expenditures based upon our strategic operating and
growth plans, which are also dependent upon our ability to produce or otherwise
obtain the financing necessary to accomplish our growth objectives. Due to the
completion of major projects, and lower-than-anticipated spending on the
Sandpiper and Line 3 Replacement projects in 2016, we expect our expansion
capital expenditures to be significantly lower in 2016 than in recent years. The
following table sets forth our estimated maintenance and expansion capital
expenditures of $900.0 million for the year ending December 31, 2016. We expect
to receive funding of approximately $430.0 million from our General Partner
based on our joint funding arrangement for the Eastern Access Projects and
Mainline Expansion Projects. Furthermore, we expect to receive funding of
approximately $55.0 million from MPC based on our joint funding arrangement for
the Sandpiper Project. Although we anticipate making these expenditures in 2016,
these estimates may change due to factors beyond our control, including
weather-related issues, construction timing, regulatory permitting, changes in
supplier prices or poor economic conditions, which may adversely affect our
ability to access the capital markets. Additionally, our estimates may also
change as a result of decisions made at a later date to revise the scope of a
project or undertake a particular capital program or an acquisition of assets.

[[Image Removed]]                  [[Image Removed]]
                                    Total Forecasted Expenditures(1)
                                             (in millions)
Liquids Projects
Eastern Access Projects            $                            215
U.S. Mainline Expansions                                        360
Sandpiper                                                       140
Line 3 Replacement                                              185
Liquids Integrity Program                                       280
Expansion Capital                                               100
Maintenance Capital Expenditures                                 60
                                                              1,340
Less joint funding from:
General Partner(2)                                              430
Third parties                                                    55
Liquids Total                      $                            855
Natural Gas Projects
Expansion Capital                  $                             50
Maintenance Capital Expenditures                                 40
                                                                 90
Less joint funding from:
MEP                                                              45
Natural Gas Total                  $                             45
TOTAL                              $                            900


[[Image Removed]]
  (1) Amounts do not include forecasted Allowance for Funds Used During
      Construction, or AFUDC.

(2) Joint funding by the General Partner is based on its respective economic

interests in the Eastern Access Projects and

U.S.
Mainline Expansions, and

does not take into account the temporary adjustment to contributions and

distributions pursuant to the amendment of the OLP limited partnership

agreement, as described above.

Distributions

We make quarterly distributions to our General Partner and the holders of our
limited partner interests in an amount equal to our "available cash." As defined
in our partnership agreement, "available cash" represents for any calendar
quarter, the sum of all of our cash receipts plus reductions in cash reserves
established in prior quarters less cash disbursements and additions to cash
reserves in that calendar quarter. We establish reserves to provide for the
proper conduct of our business, to stabilize distributions to our unitholders
and the General Partner and, as necessary, to comply with the terms of any of
our agreements or obligations. Enbridge Management, as the delegate of our
General Partner under the delegation of control agreement, computes the amount
of our "available cash."

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Enbridge Management, as the owner of our i-units, does not receive distributions
in cash. Instead, each time that we make a cash distribution to our limited
partners and General Partner, the number of i-units owned by Enbridge Management
and the percentage of our total units owned by Enbridge Management will increase
automatically under the provisions of our partnership agreement with the result
that the number of i-units owned by Enbridge Management will equal the number of
Enbridge Management's listed and voting shares that are then outstanding. The
amount of this increase in i-units is determined by dividing the cash amount
distributed per common unit by the average price of one of Enbridge Management's
listed shares on the NYSE for the 10 trading day period immediately preceding
the ex-dividend date for Enbridge Management's shares multiplied by the number
of shares outstanding on the record date. The cash equivalent amount of the
additional i-units is treated as if it had actually been distributed for
purposes of determining the distributions to be made to our General Partner.

For purposes of calculating the sum of all distributions of available cash, the
cash equivalent amount of the additional i-units that are issued when a
distribution of cash is made to our General Partner and limited partner
interests is treated as a distribution of available cash. As set forth in our
partnership agreement, we will not make cash distributions on our i-units, but
instead will distribute additional i-units such that cash is retained and used
in our operations and to finance a portion of our capital expansion projects.
During 2015, we distributed a total of 4,980,552 i-units through quarterly
distributions to Enbridge Management, compared with 4,562,088 and 3,769,989 in
2014 and 2013, respectively.

The following table represents cash we have retained in our business since January 2013 from the in-kind distribution of additional i-units:

[[Image Removed]]   [[Image Removed]]         [[Image Removed]]             [[Image Removed]]
Distribution                                     Retained from General
Payment Date         Retained for i-units               Partner              Total Cash Retained
                                                    (in millions)
2015
November 13         $                41.8     $               0.9           $               42.7
August 14                            41.0                     0.8                           41.8
May 15                               39.5                     0.8                           40.3
February 13                          38.9                     0.8                           39.7
                    $               161.2     $               3.3           $              164.5
2014
November 14         $                37.3     $               0.8           $               38.1
August 14                            36.7                     0.7                           37.4
May 15                               35.3                     0.7                           36.0
February 14                          34.6                     0.7                           35.3
                    $               143.9     $               2.9           $              146.8
2013
November 14         $                34.1     $               0.7           $               34.8
August 14                            28.9                     0.6                           29.5
May 15                               28.4                     0.6                           29.0
February 14                          22.4                     0.4                           22.8
                    $               113.8     $               2.3           $              116.1


Our current annual cash distribution rate is $2.332 per unit, or $0.58300 per
quarter, for the year ended December 31, 2015, compared with $2.22 per unit, or
$0.55500 per quarter, for the year ended December 31, 2014. We expect that all
cash distributions will be paid out of operating cash flows over the long term.
However, from time to time, we may temporarily borrow under our Credit
Facilities or use cash retained by issuance of payment in-kind distributions for
the purpose of paying cash distributions. We may do this until we realize the
full impact of assets being developed on operations or to respond to short-term
aberrations in our performance caused by market disruption events or depressed
commodity prices. As various projects are under construction, we expect our
coverage ratio to weaken as assets under construction do not generate cash flow
until they enter service and we are bearing the related financial costs. We
expect that our major capital expansion projects will be accretive to
distributable cash flow when they are operational and the coverage ratio to then
improve. Long term sustainability

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of our distributions is a key focus of the management assigned to oversee our
operation. Increases in our distribution rate are made when expected to be
sustainable for the long-term and upon the approval of the Board of Directors of
Enbridge Management.

Series AC Distributions

For periods prior to our purchase of the remaining 66.7% interest in the 
U.S.
portion of the Alberta Clipper Pipeline, the OLP was required to pay a quarterly
distribution, also referred to as the Series AC distribution amount, within 45
days of the end of each calendar quarter to the holders of the Series AC general
and limited partner interests under the terms of the then OLP partnership
agreement, consisting of the sum of: (1) the portion of the Series AC revenue
entitlement that was collected during the quarter through the transportation
rates of our Lakehead system, (2) any other cash receipts attributable to the
Series AC assets collected during the quarter, and (3) any reduction during the
quarter in the amount of the Series AC reserves established in any prior quarter
that are not utilized by the OLP, less the sum of: (a) all cash expenses related
to the Series AC assets for the quarter, (b) all cash interest expenses and
principal reductions of net borrowings for the quarter attributable to Series AC
liabilities, (c) any cash maintenance and pipeline integrity capital
expenditures for the quarter that are properly allocable to the Series AC
assets, (d) any other cash expenses for the quarter attributable to Series AC
liabilities, and (e) any increase in Series AC reserves established to provide
for the proper conduct of the business of the Series AC interests.

The following table presents distributions by the OLP for the years ended
December 31, 2015, 2014, and 2013, to our General Partner and its affiliate,
representing the noncontrolling interest in the Series AC, and to us, as the
holders of the Series AC general and limited partner interests. The
distributions were declared by the board of directors of Enbridge Management,
acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general
partner of the OLP and the Series AC interests and pursuant to the OLP's
partnership agreement. Pursuant to the OLP's partnership agreement, the final
ownership distribution for the Series AC interests was distributed to Series AC
partners of record as of the last day of the fourth quarter of 2014.

[[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]]

           [[Image Removed]]
Distribution            Distribution           Amount Paid           Amount 

Paid to the Total Series AC Declaration Date Payment Date to Partnership noncontrolling interest Distribution

                                                                        (in millions)
2015
January 29             February 13         $           13.7       $                27.5       $           41.2
2014
October 31             November 14         $           10.1       $                20.3       $           30.4
July 31                August 14                        7.4                        14.8                   22.2
April 30               May 15                           6.6                        13.1                   19.7
January 30             February 14                      6.4                        12.8                   19.2
                                           $           30.5       $                61.0       $           91.5
2013
October 31             November 14         $            7.0       $                14.1       $           21.1
July 29                August 14                        5.5                        11.0                   16.5
April 30               May 15                           7.5                        14.9                   22.4
January 30             February 14                      6.9                        13.8                   20.7
                                           $           26.9       $                53.8       $           80.7

Distribution to Series EA Interests

The following table presents distributions paid by the OLP for the years ended
December 31, 2015 and 2014, to our General Partner and its affiliate,
representing the noncontrolling interest in the Series EA, and to us, as the
holders of the Series EA general and limited partner interests. The
distributions were declared by the board of directors of Enbridge Management,
acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general
partner of the OLP and the Series EA interests.

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[[Image Removed]]              [[Image Removed]]      [[Image Removed]]     [[Image Removed]]            [[Image Removed]]
              Distribution         Distribution             Amount              Amount Paid to the         Total Series EA
            Declaration Date       Payment Date           Paid to EEP        noncontrolling interest        Distribution
                                                                                  (in millions)
2015
October 30                        November 13         $            76.1     $                      -     $            76.1
July 30                           August 14                        75.4                            -                  75.4
April 30                          May 15                           17.5                         52.3                  69.8
January 29                        February 13                      22.3                         67.0                  89.3
                                                      $           191.3     $                  119.3     $           310.6
2014
October 31                        November 14         $            14.6     $                   43.7     $            58.3
July 31                           August 14                         5.6                         16.7                  22.3
April 29                          May 15                            2.5                          6.5                   9.0
                                                      $            22.7     $                   66.9     $            89.6

Distribution to Series ME Interests

The following table presents distributions paid by the OLP for the years ended
December 31, 2015 and 2014, to our General Partner and its affiliate,
representing the noncontrolling interest in the Series ME, and to us, as the
holders of the Series ME general and limited partner interests. The
distributions were declared by the board of directors of Enbridge Management,
acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general
partner of the OLP and the Series ME interests.

[[Image Removed]]              [[Image Removed]]      [[Image Removed]]      [[Image Removed]]                 [[Image Removed]]
              Distribution         Distribution              Amount                Amount Paid to the              Total Series ME
            Declaration Date       Payment Date           Paid to EEP            noncontrolling interest             Distribution
                                                                                      (in millions)
2015
October 30                        November 13         $           32.5       $                   -             $             32.5
July 30                           August 14                       19.7                           -                           19.7
April 30                          May 15                           1.5                         4.5                            6.0
January 29                        February 13                      1.8                         5.2                            7.0
                                                      $           55.5       $                 9.7             $             65.2
2014
October 31                        November 14         $            0.6       $                 1.9             $              2.5


Environmental

Line 14 Corrective Action Orders

After the July 27, 2012 release of crude oil on Line 14, the PHMSA issued a
Corrective Action Order on July 30, 2012 and an amended Corrective Action Order
on August 1, 2012, or the PHMSA Corrective Action Orders. The PHMSA Corrective
Action Orders require us to take certain corrective actions, some of which have
already been completed and some that are still ongoing, as part of an overall
plan for our Lakehead system.

A notable part of the PHMSA Corrective Action Orders was to hire an independent
third party pipeline expert to review and assess our overall integrity program.
The third party assessment included organizational issues, response plans,
training and systems. An independent third party pipeline expert was contracted
during the third quarter of 2012 and their work is currently ongoing. The total
cost of this plan is separate from the repair and remediation costs and is not
expected to have a material impact on future results of operations.

Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating
pressure to 80% of the pressure in place at the time immediately prior to the
incident. During the fourth quarter of 2013 we received approval from the PHMSA
to remove the pressure restrictions and to return to normal operating pressures
for a period of twelve months. In December 2014, PHMSA again considered the
status of the pipeline in light of information acquired throughout 2014. On
December 9, 2014, we received a letter from PHMSA approving our request to
continue the normal operation of Line 14 without pressure restrictions.

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Lakehead Line 6B Crude Oil Release

During 2015, our cash flows were affected by the approximate $37.2 million we
paid for environmental remediation, restoration and cleanup activities resulting
from the crude oil release that occurred in 2010 on Line 6B of our Lakehead
system.

In March 2013, we and Enbridge filed a lawsuit against the insurers of our
remaining $145.0 million coverage, as one particular insurer is disputing our
recovery eligibility for costs related to our claim on the Line 6B crude oil
release and the other remaining insurers assert that their payment is predicated
on the outcome of our recovery with that insurer. We received a partial recovery
payment of $42.0 million from the other remaining insurers during the third
quarter 2013 and have since amended our lawsuit, such that it now includes only
one carrier. While we believe that our claims for the remaining $103.0 million
are covered under the policy, there can be no assurance that we will prevail in
this lawsuit. Of the remaining $103.0 million coverage limit, $85.0 million is
the subject matter of a lawsuit Enbridge filed against one particular insurer
and the remaining $18.0 million is awaiting resolution of arbitration, which is
not scheduled to occur until the fourth quarter of 2016. While we believe that
those costs are eligible for recovery, there can be no assurance we will prevail
in the arbitration. For more information, refer to Note 11. Commitments and
Contingencies of our consolidated financial statements.

Derivative Activities

We use derivative financial instruments (i.e., futures, forwards, swaps, options
and other financial instruments with similar characteristics) to manage the
risks associated with market fluctuations in interest rates and commodity
prices, as well as to reduce volatility to our cash flows. Based on our risk
management policies, all of our derivative financial instruments are employed in
connection with an underlying asset, liability and/or forecasted transaction and
are not entered into with the objective of speculating on interest rates or
commodity prices.

The following table provides summarized information about the timing and
expected settlement amounts of our outstanding commodity derivative financial
instruments based upon the market values at December 31, 2015 for each of the
indicated calendar years:

[[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]]

                        Notional(1)                2016                   2017                   2018                    2019             2020 & Thereafter           Total(2)
                                                                                              (in millions)

Swaps:

Natural gas                 13,266,817     $            -         $          0.3         $              -        $              -        $           -          $           0.3
NGL                          4,611,100                9.9                   (1.3 )                      -                       -                    -                      8.6
Crude Oil                    2,362,220                7.9                      -                        -                       -                    -                      7.9
Options:
Natural
gas - puts
purchased                    1,647,000                2.1                      -                        -                       -                    -                      2.1

Natural

gas - puts
written                      1,647,000               (2.1 )                    -                        -                       -                    -                     (2.1 )
Natural
gas - calls
purchased                    1,647,000                  -                      -                        -                       -                    -                        -
Natural
gas - calls
written                      1,647,000                  -                      -                        -                       -                    -                        -
NGL - puts
purchased                    4,242,100               54.4                    5.8                        -                       -                    -                     60.2
NGL - puts
written                         91,500               (1.5 )                    -                        -                       -                    -                     (1.5 )
NGL - calls
purchased                       91,500                  -                      -                        -                       -                    -                        -
NGL - calls
written                      4,242,100               (0.3 )                 (0.8 )                      -                       -                    -                     (1.1 )
Crude Oil - puts
purchased                    1,352,700               27.7                   10.0                        -                       -                    -                     37.7
Crude Oil - calls
written                      1,352,700                  -                   (0.6 )                      -                       -                    -                     (0.6 )
Forward
contracts:
Natural gas                172,133,704               (2.8 )                  0.1                      0.1                     0.1                    -                     (2.5 )
NGL                         11,656,204                3.1                      -                        -                       -                    -                      3.1
Crude Oil                      588,287                  -                      -                        -                       -                    -                        -
Totals                                     $         98.4         $         13.5         $            0.1        $            0.1        $           -          $         112.1


[[Image Removed]]

(1) Notional amounts for natural gas are recorded in MMBtu, whereas NGLs and

crude oil are recorded in Bbl.

(2) Fair values exclude credit adjustment gains of approximately $0.1 million at

December 31, 2015, as well as cash collateral received of $12.6 million.


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The following table provides summarized information about the timing and estimated settlement amounts of our outstanding interest rate derivatives calculated based on implied forward rates in the yield curve at December 31, 2015 for each of the indicated calendar years:

[[Image Removed]]   [[Image Removed]]     [[Image Removed]]       [[Image Removed]]       [[Image Removed]]       [[Image Removed]]      [[Image Removed]]      [[Image Removed]]
                         Notional                 2016                    2017                    2018                    2019                   2020                 Total(1)
                                                                                             (in millions)
Interest Rate
Derivatives
Interest Rate
Swaps:
Floating to Fixed   $           2,020     $          (5.7 )       $          (7.1 )       $          (5.5 )       $         (1.3 )       $           -          $         (19.6 )
Pre-issuance
hedges              $           1,350               (80.4 )                 (49.2 )                 (12.2 )                    -                     -                   (141.8 )
                                          $         (86.1 )       $         (56.3 )       $         (17.7 )       $         (1.3 )       $           -          $        (161.4 )


[[Image Removed]]

(1) Fair values exclude credit valuation adjustment gains of approximately $3.9

million at December 31, 2015.

Summary of Obligations and Commitments

The following table summarizes the principal amount of our obligations and commitments at December 31, 2015:

[[Image Removed]]        [[Image Removed]]     [[Image Removed]]     [[Image Removed]]     [[Image Removed]]     [[Image Removed]]     [[Image Removed]]     [[Image Removed]]
                                2016                  2017                  2018                  2019                  2020               Thereafter               Total
                                                                                              (in millions)
Purchase
commitments(1)           $           697.4     $               -     $               -     $               -     $               -     $               -     $           697.4
Power commitments(2)                  20.2                  20.2                  20.1                  19.7                  17.7                 132.1                 230.0
Operating leases                      19.3                  16.7                  14.8                  14.2                  14.0                  58.9                 137.9
Right-of-way                           2.0                   1.7                   1.7                   1.7                   1.5                  34.5                  43.1
Product purchase
obligations(3)                        44.2                  15.4                  24.8                  25.5                  26.5                  85.9                 222.3

Transportation/Service

contract
obligations(4)                        56.1                 112.9                 125.2                 129.2                 125.5                 338.7                 887.6
Fractionation
agreement
obligations(5)                        75.1                  74.8                  74.8                  74.8                  75.1                 156.1                 530.7
Total                    $           914.3     $           241.7     $           261.4     $           265.1     $           260.3     $           806.2     $         2,749.0


[[Image Removed]]
  (1) Represents commitments to purchase materials, primarily pipe from
      third-party suppliers in connection with our growth projects.

(2) Represents commitments to purchase power in connection with our Liquids

segment. We included certain power commitments with obligations that are

dependent on variable components. For these commitments, we only included

the determinable portion of our commitment based on the contracted usage

requirement and the current applicable contract rate.

(3) Represents long-term product purchase obligations with several third-party

suppliers to acquire natural gas and NGLs at the approximate market value at

the time of delivery.

(4) Represents the minimum payment amounts for contracts for firm transportation

and storage capacity we have reserved on third-party pipelines and storage

facilities.

(5) Represents the minimum payment amounts from contracts for firm fractionation

of our NGL supply that we reserve at third party fractionation facilities.

The payments made under our obligations and commitments for the years ended December 31, 2015, 2014 and 2013 were $729.4 million, $1.9 billion and $802.7 million, respectively.

Cash Flow Analysis

The following table summarizes the changes in cash flows by operating, investing and financing for each of the years indicated:

[[Image Removed]]           [[Image Removed]]     [[Image Removed]]     [[Image Removed]]
                                            For the year ended December 31,
                                   2015                  2014                  2013
                                                     (in millions)
Total cash provided by
(used in):
Operating activities        $        1,030.8      $          816.8      $        1,212.4
Investing activities                (2,126.4 )            (2,976.6 )            (2,642.9 )
Financing activities                 1,045.8               2,192.9               1,367.4
Net increase (decrease)
in cash and cash
equivalents                            (49.8 )                33.1                 (63.1 )
Cash and cash equivalents
at beginning of year                   197.9                 164.8                 227.9
Cash and cash equivalents
at end of period            $          148.1      $          197.9      $          164.8


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Changes in our working capital accounts are shown in the following table and
discussed below:

[[Image Removed]]        [[Image Removed]]      [[Image Removed]]      [[Image Removed]]
                                          For the year ended December 31,
                                 2015                   2014                   2013
                                                   (in millions)
Changes in operating
assets and
liabilities, net of
acquisitions:
Receivables, trade and
other                    $          20.9        $           1.7        $         125.0
Due from General
Partner and affiliates             (17.5 )                  0.7                  (12.6 )
Accrued receivables                182.4                  (50.1 )                286.1
Inventory                           53.3                  (10.7 )                (21.2 )
Current and long-term
other assets                       (29.5 )                (47.1 )                (24.1 )
Due to General Partner
and affiliates                      46.0                   22.4                   79.1
Accounts payable and
other                                3.5                 (101.1 )                 85.1
Environmental
liabilities                        (43.7 )               (143.1 )               (174.9 )
Accrued purchases                 (229.6 )                (89.9 )                 13.8
Interest payable                    24.5                    6.6                    4.3
Property and other
taxes payable                        7.2                   26.1                   (0.7 )
Net change in working
capital accounts         $          17.5        $        (384.5 )      $         359.9

Year ended December 31, 2015 compared with year ended December 31, 2014 Operating Activities

Net cash provided by our operating activities increased $214.0 million during the year ended December 31, 2015, compared with the same period in 2014, primarily due to:

• Increased cash from inventory of $64.0 million primarily resulting from an

overall reduction of commodity inventories as compared with the prior year;

• Increased cash from reduced payments for environmental liabilities of $99.4

million associated with the accrual for the Line 6B crude oil release;

• Increased cash from accounts payable and other as working capital of $104.6

million resulting from general timing differences for cash payments

associated with our third-party accounts, including increased payments at

       the end of 2014 to third-party accounts in connection with the
       implementation of a new accounts payable system;

• Net increased cash from accrued receivables and accrued purchases of $92.8

million primarily due to a decline in commodity prices in 2015, which

resulted in net collections of cash from higher priced receivables earlier

in the year;

• Increased cash from net income, after non-cash adjustments, of $49.9

       million, primarily due to increased operating results in the Liquids
       segment; and

• Decreased cash from the cash settlement of pre-issuance hedges related to

interest of $237.9 million resulting from the expiration of several large

pre-issuance hedge contracts in connection with issuance of long-term debt.


Investing Activities

Net cash used in our investing activities decreased by $850.2 million during the year ended December 31, 2015, compared with 2014, primarily due to:

• Decreased cash used for additions to property, plant and equipment, net of

construction payables, of $816.8 million. We placed a large number of major

projects related to Eastern Access and Mainline Expansion into service in

2014 and early 2015. As a result, capital expenditures for 2015 were lower

compared to 2014 as projects reached completion;

• Decreased cash provided by restricted cash of $93.0 million resulting from

       fewer amounts remitted to the Enbridge subsidiary for sales of our
       receivables in accordance with our Receivables Agreement;


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   •   Changes in contributions to fund our joint venture investment and

distributions in excess of earnings in the Texas Express NGL system. This

resulted in a net decrease of cash used of $16.7 million, primarily due to

higher capital spending on Texas Express in 2014 and higher distributions

       from Texas Express in 2015 resulting from higher volumes and demand
       charges; and

• Increased cash used for asset acquisitions of $84.8 million due to MEP's

acquisition of NGR's midstream assets in February 2015. For further details

regarding this acquisition, see Item 1. Financial Statements and

Supplementary Data, Note 4. Acquisitions.

Financing Activities

Net cash provided by our financing activities decreased $1,147.1 million for the year ended December 31, 2015, compared with 2014, primarily due to:

• Decreased cash from decreased net borrowings on our credit facility of

$1,105.0 million;

• Decreased cash from net repayments on the commercial paper program of

$598.2 million;

• Decreased cash provided by contributions from our noncontrolling interest

       of $528.3 million for ownership interests in the Mainline Expansion
       Projects, Eastern Access Projects and Sandpiper Project;

• Decreased cash from increased repayments of $294.0 million to the General

Partner for the A1 Term Note. The remaining outstanding balance of $306.0

million was repaid on January 2, 2015; and

• Decreased cash from increased distributions to our limited partners of

$108.0 million and to our noncontrolling interest of $185.4 million due to

phases of the Eastern Access Project and Mainline Expansion Project being

placed into service.

These decreases in net cash provided by our financing activities were partially offset by the following:

• Increased cash provided by the issuance of debt of $1,177.0 million, after

debt issuance costs. We issued $1.6 billion of debt during 2015 and $398.1

million of debt during 2014;

• Increased cash from our Class A unit issuance, including our General

Partner's contributions, of $294.8 million in March 2015. We had no similar

issuances in 2014; and

• Increased cash from reduced repayments on our long-term debt of $200.0

million.

Year ended December 31, 2014 compared with year ended December 31, 2013 Operating Activities

Net cash provided by our operating activities decreased $395.6 million for the
year ended December 31, 2014, compared to the same period in 2013, primarily due
to a decrease in our working capital accounts of $744.4 million coupled with
non-cash items of $235.7 million. These decreases were partially offset by a
$579.6 million increase in net income for the year ended December 31, 2014, as
compared to 2013.

The changes in our operating assets and liabilities, net of acquisitions as
presented in our consolidated statements of cash flow for the year ended
December 31, 2014, compared with the same period in 2013, is primarily the
result of items listed below in addition to general timing differences for cash
receipts and payment associated with our third-party accounts. The main items
affecting our cash flows from operating assets and liabilities include the
following:

• The change in accrued receivables and trade receivables during 2013 was

favorable due to the sale of $275.5 million of our net accrued receivables

and $90.1 million of trade receivables to a subsidiary of Enbridge pursuant

to the Receivables Agreement;

• Decreased cash flows from changes in accounts payable and other was due to

general timing differences for cash payments associated with our

third-party accounts, including increased payments to third-party accounts

at the end of 2014 due to the implementation of a new accounts payable

system; and

• Decreased cash flows from changes in accrued purchases are primarily the

       result of lower levels of accrued purchases at December 31, 2014, which
       stem from lower volumes purchased at lower prices as compared to the prior
       year.


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The above decreases were coupled with a $235.7 million decrease in our non-cash
items for the year ended December 31, 2014, compared to December 31, 2013,
partially offset by an increase in net income of $579.6 million. The decrease in
non-cash items primarily consisted of the following:

• Decreased environmental costs of $225.9 million mainly attributed to $302.0

million in additional estimated costs recognized during 2013 related to the

Line 6B crude oil release, while only recognized $85.9 million in

additional estimated costs were recognized for the year ended December 31,

2014 related to the Line 6B crude oil release; and

• Increased derivative net gains of $100.6 million primarily as a result of

fluctuations in commodity prices.

Partially offsetting the non-cash item decreases above were the following:

• Increased depreciation and amortization of $70.2 million due to projects

placed in service in 2014;

• Decreased gains on sale of assets of $17.1 million in 2014, as there was

only a sale of assets in 2013; and

• Increased asset impairment charges due to the impairment of the right of

way of a Propylene pipeline for $15.6 million.

Investing Activities

Net cash used in our investing activities during the year ended December 31,
2014, increased by $333.7 million, compared to 2013, primarily due to the
increased payments on our construction payables of $331.9 million coupled with
increased additions to property, plant and equipment in 2014 related to various
enhancement projects of $198.6 million. Partially, offsetting these increases
were the following:

• Decreased cash contributions of $151.9 million combined with decreased

       allowance for interest during construction associated with our joint
       venture project, the Texas Express NGL system, as the project went into
       service at the end of 2013; and

• Decreased restricted cash balance of $41.8 million consisting of cash

collections related to the receivables sold that have yet to be remitted to

the Enbridge subsidiary in accordance with the Receivables Agreement.


Financing Activities

Net cash provided by our financing activities increased $825.5 million for the year ended December 31, 2014, compared to 2013, primarily due to the following:

• Increased net borrowings on our commercial paper of $1.2 billion for the

year ended December 31, 2014;

• Increased net proceeds from borrowings on our Credit Facilities of $850.0

million primarily attributable to borrowings under our 364-Day Credit

Facility in 2014;

• Increased net proceeds from borrowings on our long-term debt of $398.1

million due to us issuing private placement debt at MEP in 2014; and

• Increased contributions from noncontrolling ownership interests in the

Mainline Expansion Projects, Eastern Access Projects, Sandpiper, and from

Midcoast Holdings for its ownership in MEP of $243.1 million, partially

offset by increased distributions to noncontrolling interest of $100.2

million.

Offsetting the proceeds above were the following:

• Decreased net proceeds in 2014 of $1.2 billion due to no preferred unit

issuances in 2014 while we had a $1.2 billion preferred unit issuance in

2013; and

• Decreased net proceeds from unit issuances, including our General Partner's

contributions of $519.3 million from 2013 compared to no issuances in 2014.

OFF-BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements.

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REGULATORY MATTERS
FERC Transportation Tariffs
Lakehead System

On February 27, 2015, we filed FERC Tariff No. 43.16.0, our annual rate
adjustment with the FERC for the Facilities Surcharge Mechanism, or FSM,
component of the Lakehead system with rates effective April 1, 2015. The FSM
allows Lakehead to recover costs associated with particular shipper-approved
projects through an incremental cost-of-service based surcharge that is layered
on top of the base index rates. The FSM surcharge reflects our projected costs
for these shipper-approved projects for 2015 and an adjustment for the
difference between estimated and actual costs and throughput for the prior year.
The surcharge is applicable to all volumes entering our system from the
effective date of the tariff, which we recognize as revenue when the barrels are
delivered, typically a period of approximately 30 days from the date shipped.

This tariff filing decreased our transportation rate for heavy crude oil
movements from the Canadian border to the 
Chicago, Illinois
 area by
approximately $0.10 per barrel, to approximately $2.39 per barrel. The tariff
filing also decreased our transportation rate for light crude oil movements from
the Canadian border to the 
Chicago, Illinois
 area by approximately $0.08 per
barrel, to approximately $1.98 per barrel. These decreases were primarily the
result of an increase in forecasted 2015 throughput and the use of a nine-month
recovery period from April through December rather than a five-month recovery
period from August to December that was used for 2014. The shorter recovery
period in 2014 was due to a delayed toll filing, discussed further below, as a
result of negotiations with shippers concerning certain components of the tariff
rate structure.

On May 29, 2015, we filed FERC tariff No. 43.17.0, with an effective date of
July 1, 2015, for the Lakehead system. We increased rates in compliance with the
indexed rate ceilings allowed by the FERC, which incorporates the multiplier of
1.045829 issued by the FERC on May 14, 2015, in Docket No. RM93-11-000.

North Dakota System

Effective February 1, 2015, FERC tariff No. 3.6.0 established a new interconnection at

Tioga, North Dakota
.
Effective April 1, 2015, FERC tariff No. 3.7.0 updated the calculation of the
Phase 5 Looping and Phase 6 Mainline surcharges. These surcharges are
cost-of-service based surcharges that are adjusted each year to actual costs and
volumes and are not subject to the FERC indexing methodology. The filing
decreased our average transportation rates for all crude oil movements on our
North Dakota
 system with a destination of 
Clearbrook, Minnesota
 by an average of
approximately $0.44 per barrel, to an average of approximately $1.77 per barrel.
The Phase 5 Looping surcharge decreased primarily due to an increase in
forecasted throughput, and the Phase 6 Mainline surcharge decreased due to an
increase in forecasted throughput and in order to return prior period
over-recoveries to shippers.

Effective April 22, 2015, FERC tariff No. 3.8.0 cancelled the transportation
rate from 
Sherwood, North Dakota
 to 
Clearbrook, Minnesota
, as the pipeline no
longer provides service from that receipt point.

Effective July 1, 2015, FERC tariff No. 3.10.0 increased rates in compliance
with the indexed rate ceilings allowed by the FERC, which incorporates the
multiplier of 1.045829 issued by the FERC on May 14, 2015, in Docket No.
RM93-11-000. Additionally, as per the Transportation Services Agreement, or TSA,
this tariff adjusted the operating cost charge component of the committed
trunkline rates to 
Berthold, North Dakota
 to the actual operating costs and
throughput volumes for 2014 and the forecasted operating costs and throughput
for 2015.

Also effective July 1, 2015, FERC tariff No. 3.11.0 discounted the existing uncommitted rate from

Berthold
(pump-over),
North Dakota
to
Berthold, North Dakota
. The new tariff rate of $0.27 per barrel reflects a rate decrease of $0.556 per barrel.
Effective December 1, 2015, FERC tariff 3.13.0 was filed to establish an initial
gathering service and charge at Little Muddy (
Williams County
), 
North Dakota
.
The $0.1137 per barrel interconnection rate resulted from a shipper's request
for a pipeline interconnection at that location.

On November 12, 2015, we filed FERC tariff 3.15.0 to cancel trunkline
transportation rates from 
Glenburn
 (
Renville County
), 
North Dakota
 and 
Newburg
(
Bottineau County
), 
North Dakota
 to 
Clearbrook
 (
Clearwater County
), 
Minnesota
,
as well as to cancel the gathering rate from 
Newburg Area
, 
North Dakota
 to
Newburg
 (
Bottineau County
), 
North Dakota
, as the pipeline is no longer providing
service from those receipt points.

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Bakken system

Effective January 1, 2015, FERC tariff No. 3.2.0 was filed to reflect a change
in the international joint rates. In accordance with FERC policy, each of the
international joint rates was equal to or less than the sum of the local rates
for the component movements from 
Berthold, North Dakota
 to 
Cromer, Manitoba
.

Effective July 1, 2015, FERC tariff No. 2.2.0 increased rates in compliance with
the indexed rate ceilings allowed by the FERC, which incorporates the multiplier
of 1.045829 issued by the FERC on May 14, 2015, in Docket No. RM93-11-000.

Also effective July 1, 2015, FERC tariff No. 3.4.1 adjusted rates in accordance
with the TSA that was included in the Petition for Declaratory Order filed on
August 26, 2010, in Docket No. OR10-19-000. Additionally, as per the TSA, this
tariff adjusted the operating cost charge component of the committed
international joint rates to 
Cromer, Manitoba
 to the actual operating costs and
throughput volumes for 2014 and the forecasted operating costs and throughput
for 2015.

Ozark System

Effective July 1, 2015, FERC tariff No. 48.5.0 increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 1.045829 issued by the FERC on May 14, 2015, in Docket No. RM93-11-000.

Effective December 1, 2015, our 
Ozark
 system filed FERC Tariff 48.6.0 to
increase its rate from $0.6759 to $0.8403. This filing was made to allow for
recovery of costs related to the capital expenditures required to maintain the
integrity of the pipeline.

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Revenues from Contracts with Customers

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, which
outlines a single comprehensive model for entities to use in accounting for
revenue arising from contracts with customers and supersedes most current
revenue recognition guidance, including industry-specific guidance. In July
2015, the FASB delayed the effective date of the new revenue standard by one
year. This accounting update is effective for annual and interim periods
beginning on or after December 15, 2017, and may be applied on either a full or
modified retrospective basis. We are currently evaluating which transition
approach we will apply and the impact that this pronouncement will have on our
consolidated financial statements.

Consolidation

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, which
addresses concerns about the current accounting for consolidation of certain
legal entities. It makes targeted amendments to the current consolidation
guidance and ends the deferral granted to certain entities from applying the
variable interest entity, or VIE, guidance. Among other things, the amended
standard revised the consolidation model and guidance for limited partnerships,
which included the elimination of the presumption that a general partner should
consolidate a limited partnership and the consolidation analysis of reporting
entities that are involved with VIEs, particularly those that have fee
arrangements and related party relationships. This accounting update is
effective for annual periods, and for interim periods within those annual
periods, beginning after December 15, 2015. Early adoption is permitted, and the
new standard may be adopted either retrospectively or using a modified
retrospective approach. We do not anticipate that our ultimate consolidation
conclusions for non-wholly-owned subsidiaries will change upon adoption of the
revised guidance. However, we believe that additional VIE disclosures will be
required.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our selection and application of accounting policies is an important process
that has developed as our business activities have evolved and as new accounting
pronouncements have been issued. Accounting decisions generally involve an
interpretation of existing accounting principles and the use of judgment in
applying those principles to the specific circumstances existing in our
business. We believe the proper implementation and consistent application of all
applicable accounting principles is critical. However, not all situations we
encounter are specifically addressed in the accounting literature. In such
cases, we must use our best judgment to implement accounting policies that
clearly and accurately present the substance of these situations. We accomplish
this by analyzing similar situations and the accounting guidance governing them
and consulting with experts about the appropriate interpretation and application
of the accounting literature to these situations.

In addition to the above, certain amounts included in or affecting our
consolidated financial statements and related disclosures must be estimated,
requiring us to make certain assumptions with respect to values or conditions
that cannot be known with certainty at the time the consolidated financial
statements are prepared. These estimates affect the reported amounts of assets,
liabilities, revenues, expenses and related disclosures with respect to
contingent assets and liabilities. The basis for our estimates is historical
experience, consultation with experts and other sources we believe to be
reliable. While we believe our estimates are appropriate, actual results can and
often do differ from these estimates. Any effect on our business, financial
position, results of operations and cash flows resulting from revisions to these
estimates are recorded in the period in which the facts that give rise to the
revision become known.

For a summary of our significant accounting policies, refer to Item 8. Financial
Statements and Supplementary Data, Note 2. Summary of Significant Accounting
Policies. We believe our critical accounting policies discussed in the following
paragraphs address the more significant judgments and estimates we use in the
preparation of our consolidated financial statements. Each of these areas
involve complex situations and a high degree of judgment either in the
application and interpretation of existing accounting literature or in the
development of estimates that affect our consolidated financial statements. Our
management has discussed the development and selection of the critical
accounting policies and estimates related to the reported amounts of assets,
liabilities, revenues and expenses and disclosure of contingent liabilities with
the Audit, Finance & Risk Committee of Enbridge Management's board of directors.

Liquids Revenue Recognition

Revenues of our Liquids segment are primarily derived from two sources,
interstate transportation of crude oil and liquid petroleum under tariffs
regulated by the FERC and contract storage revenues related to our crude oil
storage assets. The tariffs established for our interstate pipelines specify the
amounts to be paid by shippers for transportation services we provide between
receipt and delivery locations and the general terms and conditions of
transportation services on the respective pipeline systems. In our Liquids
segment, we generally do not own the crude oil and liquid petroleum that we
transport or store, and therefore, we do not assume significant direct commodity
price risk. Some long-term take-or-pay contracts contain make-up-rights.
Make-up-rights are granted when minimum volume commitments are not utilized
during the period but under certain circumstances can be used to offset overages
in future periods, subject to expiration periods. We recognize revenue
associated with make-up rights at the earlier of when the make-up volume is
shipped, the make-up right expires, or when it is determined that the likelihood
that the shipper will utilize the make-up right is remote. The "remote"
determination is a matter of management judgment that requires us to make
assumptions regarding, for example, general economic conditions impacting our
assets, remaining capacity on the pipeline, shipper history and other factors.
Such assumptions are subject to uncertainty, and changes in conditions used to
make these assumptions could result in significant changes in the timing of our
revenue recognition on these contracts.

Revenue Recognition and the Estimation of Revenues and Commodity Costs

In general, we recognize revenue when delivery has occurred or services have
been rendered, pricing is determinable and collectability is reasonably assured.
We estimate our current month revenue and commodity costs to permit the timely
preparation of our consolidated financial statements. We generally cannot
compile actual billing information nor obtain actual vendor invoices within a
timeframe that would permit the recording of this actual data before our
preparation of the consolidated financial statements. As a result, we record an
estimate each month for our operating revenues and commodity costs based on the
best available volume and price data for natural gas or crude oil delivered and
received, along with an adjustment of the prior month's estimate to equal the
prior month's actual data. As a result, there is one month of estimated data
recorded in our operating revenues and commodity

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costs for each period reported. We believe that the assumptions underlying these
estimates will not be significantly different from the actual amounts due to the
routine nature of these estimates and the consistency of our processes.

Regulated Operations

The rates for a number of our projects are based on a cost-of-service recovery
model that follows the FERC's authoritative guidance and are subject to annual
filing requirements with the FERC. Under our cost-of-service tolling
methodology, we calculate tolls based on forecast volumes and costs, which is
subject to uncertainty. A difference between forecast and actual results causes
an over or under recovery in any given year. Under the authoritative accounting
provisions applicable to our regulated operations, over or under recoveries are
recognized in the financial statements in the current period. This accounting
model matches earnings to the period with which they relate and conforms to how
we recover our costs associated with these projects through the annual
cost-of-service filings with the FERC and through toll rate adjustments with our
customers.

Useful Life of Property, Plant and Equipment

We record property, plant and equipment at its original cost, which we
depreciate on a straight-line basis over the lesser of its estimated useful life
or the estimated remaining lives of the crude oil or natural gas production in
the basins the assets serve. Our determination of the useful lives of property,
plant and equipment requires us to make various assumptions, including the
supply of and demand for hydrocarbons in the markets served by our assets,
normal wear and tear of the facilities, and the extent and frequency of
maintenance programs. We routinely utilize consultants and other experts to
assist us in assessing the remaining lives of the crude oil or natural gas
production in the basins we serve. Changes in any of our assumptions may alter
the rate at which we recognize depreciation in our consolidated financial
statements. Uncertainties that impact these assumptions include changes in laws
and regulations that limit the estimated economic life of an asset, economic
conditions and supply and demand in basins we serve. Based on the results of
these assessments we may make modifications to the assumptions we use to
determine our depreciation rates.

Assessment of Recoverability of Property, Plant and Equipment and Intangible Assets

We evaluate the recoverability of our property, plant and equipment and
intangible assets when events or circumstances such as economic obsolescence,
the business climate, legal and other factors indicate we may not recover the
carrying amount of the assets. Our intangible assets primarily consist of
customer contracts for the purchase and sale of natural gas, natural gas supply
opportunities and contributions we have made in aid of construction activities
that will benefit our operations, as well as workforce contracts and customer
relationships. We continually monitor our businesses, the market and business
environments to identify indicators that could suggest an asset may not be
recoverable. We evaluate the asset for recoverability by estimating the
undiscounted future cash flows expected to be derived from operating the asset
as a going concern. These cash flow estimates require us to make projections and
assumptions for many years into the future for pricing, demand, competition,
operating cost, contract renewals and other factors. If the total of the
undiscounted future cash flows is less than the carrying amount of the property,
plant and equipment or intangible assets, we write the assets down to fair
value. We recognize an impairment loss when the carrying amount of the asset
exceeds its fair value as determined by quoted market prices in active markets
or present value techniques. The determination of the fair value using present
value techniques requires us to make projections and assumptions regarding
future cash flows and weighted average cost of capital. Any changes we make to
these projections and assumptions could result in significant revisions to our
evaluation of the recoverability of our property, plant and equipment and
intangible assets and the recognition of an impairment loss in our consolidated
statements of income.

We believe the assumptions used in evaluating recoverability of our assets are
appropriate and result in reasonable estimates of the fair values of our assets.
However, the assumptions used are subject to uncertainty, and declines in the
future performance or cash flows of our assets, changes in business conditions,
such as commodity prices and drilling, or increases to our weighted average cost
of capital assumptions due to changes in credit or equity markets may result in
the recognition of impairment charges, which could be significant.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from changes in
interest rates on our variable rate debt obligations and fluctuations in
commodity prices of natural gas, NGLs, condensate, crude oil and fractionation
margins. Fractionation margins represent the relative difference between the
price we receive from NGL and condensate sales and the corresponding commodity
costs of natural gas and natural gas liquids we

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purchase for processing. We use a variety of derivative financial instruments
including futures, forwards, swaps, options and other financial instruments with
similar characteristics to create offsetting positions to specific commodity or
interest rate exposures.

We record all derivative financial instruments at fair market value in our
consolidated statements of financial position, which we adjust on a recurring
basis each period for changes in the fair market value, and refer to as marking
to market, or mark-to-market. The fair market value of these derivative
financial instruments reflects the estimated amounts that we would pay to
transfer a liability or receive to sell an asset in an orderly transaction with
market participants to terminate or close the contracts at the reporting date,
taking into account the current unrealized losses or gains on open contracts. We
apply a mid-market pricing convention, or the "market approach," to value
substantially all of our derivative instruments.

Price assumptions we use to value our non-qualifying derivative financial
instruments can affect net income for each period. We use published market price
information where available, or quotations from OTC market makers to find
executable bids and offers. We may also use these inputs with internally
developed methodologies that result in our best estimate of fair value. The
valuations also reflect the potential impact of liquidating our position in an
orderly manner over a reasonable period of time under present market conditions,
including credit risk of our counterparties. The amounts reported in our
consolidated financial statements change quarterly as these valuations are
revised to reflect actual results, changes in market conditions or other
factors, many of which are beyond our control.

We employ a hierarchy which prioritizes the inputs we use to measure recurring
fair value into three distinct categories based upon whether such inputs are
observable in active markets or unobservable. We classify assets and liabilities
in their entirety based on the lowest level of input that is significant to the
fair value measurement. Our methodology for categorizing assets and liabilities
that are measured at fair value pursuant to this hierarchy gives the highest
priority to unadjusted quoted prices in active markets and the lowest level to
unobservable inputs.

Commitments, Contingencies and Environmental Liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance
with environmental regulations that relate to past or current operations. We
expense amounts we incur for remediation of existing environmental contamination
caused by past operations that do not benefit future periods by preventing or
eliminating future contamination. We record liabilities for environmental
matters when assessments indicate that remediation efforts are probable, and the
costs can be reasonably estimated. Estimates of environmental liabilities are
based on currently available facts, existing technology and presently enacted
laws and regulations taking into consideration the likely effects of inflation
and other factors. These amounts also consider prior experience in remediating
contaminated sites, other companies' clean-up experience and data released by
government organizations. Our estimates are subject to revision in future
periods based on actual costs or new information and are included in
"Environmental liabilities" and "Other long-term liabilities" in our
consolidated statements of financial position at their undiscounted amounts. We
always have the potential of incurring additional costs in connection with
environmental liabilities due to variations in any or all of the categories
described above, including modified or revised requirements from regulatory
agencies, in addition to fines and penalties, as well as expenditures associated
with litigation and settlement of claims. We evaluate recoveries from insurance
coverage separately from the liability and, when recovery is probable, we record
and report an asset separately from the associated liability in our consolidated
financial statements.

We recognize liabilities for other commitments and contingencies when, after
fully analyzing the available information, we determine it is either probable
that an asset has been impaired, or that a liability has been incurred and the
amount of impairment or loss can be reasonably estimated. When a range of
probable loss can be estimated, we accrue the most likely amount, or if no
amount is more likely than another, we accrue the minimum of the range of
probable loss. We expense legal costs associated with loss contingencies as such
costs are incurred. We believe that the estimates discussed herein are
reasonable, however actual results could differ and it could result in material
adjustments in results of operations between periods.

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SUBSEQUENT EVENTS
Distribution to Partners

On January 29, 2016, the board of directors of Enbridge Management declared a
distribution payable to our partners on February 12, 2016. The distribution was
paid to unitholders of record as of February 5, 2016, of our available cash of
$259.6 million at December 31, 2015, or $0.5830 per limited partner unit. Of
this distribution, $216.0 million was paid in cash, $42.7 million was
distributed in i-units to our i-unitholder and $0.9 million was retained from
our General Partner in respect of the i-unit distribution to maintain its 2%
general partner interest.

Distribution to Series EA Interests

On January 29, 2016, the board of directors of Enbridge Management, acting on
behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of
the OLP and a holder of the Series EA interests, declared a distribution payable
to the holders of the Series EA general and limited partner interests. The OLP
paid the entire $79.2 million distribution to us.

Distribution to Series ME Interests

On January 29, 2016, the board of directors of Enbridge Management, acting on
behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of
the OLP and a holder of the Series ME interests, declared a distribution payable
to the holders of the Series ME general and limited partner interests. The OLP
paid the entire $40.8 million distribution to us.

Distribution from MEP

On January 28, 2016, the board of directors of Midcoast Holdings, L.L.C., acting
in its capacity as the general partner of MEP, declared a cash distribution
payable to their partners on February 12, 2016. The distribution was paid to
unitholders of record as of February 5, 2016, of MEP's available cash of $16.5
million at December 31, 2014, or $0.3575 per limited partner unit. MEP paid $7.6
million to their public Class A common unitholders, while $8.9 million in the
aggregate was paid to us with respect to our Class A common units, subordinated
units and to Midcoast Holdings, L.L.C. with respect to its general partner
interest.

Midcoast Operating Distribution

On January 28, 2016, the general partner of Midcoast Operating declared a cash
distribution by Midcoast Operating payable to its partners of record as of
February 5, 2016. Midcoast Operating paid $25.9 million to us and $27.6 million
to MEP.

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