Taylor NGL Limited Partnership
TSX : TAY.UN
TSX : TAY.DB

Taylor NGL Limited Partnership

November 01, 2006 16:01 ET

Taylor NGL Limited Partnership Third Quarter 2006 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 1, 2006) - Taylor NGL Limited Partnership (TSX:TAY.UN) (TSX:TAY.DB):

Q3 2006 HIGHLIGHTS

- Funds Provided by Operations were a record $12.7 million, or 29.9 cents per unit, of which $7.9 million, or 18.5 cents per unit, was distributed to unitholders.

- Net Operating Income was a record $16.2 million, up 30 percent from Q3 2005 and up 8 percent from Q2 2006.

- The Partnership's net natural gas liquids (NGL) sales averaged 19,722 barrels per day, up 14 percent from Q3 2005.

- The Partnership's net natural gas volume processed averaged 434 MMscf per day, up slightly from Q3 2005.

The following tables highlight Taylor's operational and financial results for the three months and nine months ended September 30, 2006 compared to the results for the same periods in 2005:



---------------------------------------------------------------------------
(dollars in thousands except volume Three Months ended September 30
and unit amounts) 2006 2005 Change
---------------------------------------------------------------------------

Natural gas processed (MMscf per day) 434 431 1%
NGL sales (barrels per day) 19,722 17,315 14%
Total revenue 61,949 61,788 0%
Feedstock cost 35,720 39,598 -10%
Net income 7,331 5,090 44%
Basic per unit 0.17 0.12 42%
Net Operating Income 16,150 12,397 30%
Cash Available for Distribution 11,208 9,122 23%
Distributions paid to unitholders 7,872 7,550 4%
per unit 0.1850 0.1775 4%
Units outstanding at end of period 42,553,490 42,531,490 0%
---------------------------------------------------------------------------

---------------------------------------------------------------------------
(dollars in thousands except volume and Nine Months ended September 30
unit amounts) 2006 2005 Change
---------------------------------------------------------------------------

Natural gas processed (MMscf per day) 452 409 11%
NGL sales (barrels per day) 20,035 16,391 22%
Total revenue 190,448 146,670 30%
Feedstock cost 115,301 91,548 26%
Net income (1) 20,980 9,700 116%
Basic per unit 0.49 0.25 96%
Net Operating Income 45,463 27,043 68%
Cash Available for Distribution 32,050 20,719 55%
Distributions paid to unitholders 23,187 19,535 19%
per unit 0.5450 0.5150 6%
Units outstanding at end of period 42,553,490 42,531,490 0%
---------------------------------------------------------------------------

(1) 2005 Net Income is before management reorganization costs


CONFERENCE CALL

A conference call to discuss these results will be held on Thursday, November 2, 2006 at 8:30 a.m. MT (10:30 a.m. ET). To participate in the conference call, please dial 416-695-9712 in the Toronto area and 1-800-772-8997 from all other areas of Canada. A recording of the call will be available for replay until November 9, 2006 at 416-695-5275 or 1-888-509-0081 (passcode 634129) or by following the links on Taylor's website, www.taylorngl.com.

MANAGEMENT'S DISCUSSION AND ANALYSIS

As at November 1, 2006

The following should be read in conjunction with the consolidated financial statements and notes of Taylor NGL Limited Partnership (the Partnership) for the year ended December 31, 2005 and the nine months ended September 30, 2006. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). Additional information relating to the Partnership, including the Partnership's Annual Information Form, is available on SEDAR at www.sedar.com.

Volumetric information for each of the Partnership's facilities is available at www.taylorngl.com under Investor Info: Facts & Figures: Production.

This Management's Discussion and Analysis contains certain forward-looking statements that are based on the Partnership's current expectations, estimates, projections and assumptions in light of its experience and its view of historical trends. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expects", "projects", "plans", "anticipates", "targets" and similar expressions. These statements are not guarantees of future performance and are subject to a number of risks and uncertainties as detailed in the Partnership's Annual Information Form under the heading "Risk Factors". Undue reliance should not be placed on these forward-looking statements, as known and unknown risks and uncertainties may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Examples of areas of risk and uncertainty include: volume of natural gas delivered for processing at the Partnership's facilities; ability of the facilities to process the natural gas delivered; cost of operating the facilities; cost of maintaining the facilities; and volume and value, net of feedstock costs, of the Partnership's proprietary products such as NGL, frac oil and CO2. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. Such forward-looking statements are expressly qualified by the above statements.

Tabular amounts are expressed in thousands of dollars except per unit amounts. All figures are in Canadian dollars unless otherwise stated. All volumes are net to the Partnership unless otherwise stated.

Taylor uses the industry standard term "Funds Provided by Operations", which has the same GAAP definition as "cash provided by operations before changes in non-cash working capital".

The term "Cash Available for Distribution" refers to the amount of cash that has been, or is, available for distribution to the Partnership's unitholders prior to any withholdings or reserves that the Board of Directors may make pursuant to the terms of the Partnership's Limited Partnership Agreement. Cash Available for Distribution is defined as Funds Provided by Operations plus adjustments for one-time items and less "Sustaining Capital" and "Reserve for Future Commitments". One-time items are specifically described when they occur.

Sustaining Capital is defined as capital expenditures necessary to maintain the safe and efficient operation of Taylor's facilities for the long-term. Sustaining Capital items are not expensed due to the long-term nature of these investments.

Reserve for Future Commitments is defined as expenditures known by the Partnership with respect to prior periods, but not deducted from net income due to guidelines established by the CICA. An example of such expenditure is the cost of the Restricted Share Units (RSUs) awarded under the Partnership's Long-term Incentive Plan (LTIP). The number of RSUs awarded is based on the results achieved over a specific fiscal period. According to the terms of the LTIP, the awards vest in future periods. Under section 3870 of the CICA Handbook, RSUs are classified as stock appreciation rights and therefore are recorded as a compensation expense over the vesting period.

Taylor uses the term "Net Operating Income" to assist in assessing the ability of the Partnership to generate cash from normal operations. Net Operating Income is defined as natural gas liquids sales plus fee income, less shrinkage gas expense, operating costs and overhead recovery fees.

The terms Funds Provided by Operations, Cash Available for Distribution, Sustaining Capital, Reserve for Future Commitments and Net Operating Income are not recognized under Canadian GAAP. Therefore, these terms have no standardized meaning and may not be comparable to similarly defined amounts presented by other issuers.

Overview of Third Quarter 2006

Production and Operations Summary

Taylor achieved record monthly NGL sales of 21,235 barrel per day in August. For the third quarter sales averaged 19,722 barrels per day, up 14 percent over third quarter 2005. Current quarter NGL sales were less than second quarter 2006 as a result of maintenance activities during September at both the Younger Extraction Plant and the Harmattan Complex that required curtailment of natural gas volume processed. At quarter end, both plants had been returned to full operation.

Net natural gas volumes processed by Taylor during the third quarter of 2006 was 434 MMscf per day, compared to 431 MMscf per day in the comparable quarter of 2005. Of Taylor's total volume, the Harmattan Complex processed an average 112 MMscf per day and the RET Complex averaged 51 MMscf per day. The Younger and Joffre extraction plants processed a combined average 271 MMscf per day.

Taylor sets production rates at the Younger and Joffre extraction plants largely in response to prevailing NGL margins. If the NGL margin is less than the variable operating costs, then production is not economically justified. The NGL margin is defined as the difference between the sales price of NGL and the cost of the natural gas purchased for shrinkage make-up. Taylor reports an indicative margin, expressed in dollars per barrel of NGL, which is derived from Edmonton postings for propane, butane and condensate and the daily AECO natural gas price. In the third quarter, this benchmark NGL margin averaged $26.12 per barrel compared to $9.39 per barrel in the third quarter of 2005 and up from $23.04 per barrel in the second quarter of 2006.

During the third quarter, the Younger Extraction Plant processed an average 210 MMscf per day to produce 11,124 barrels per day of NGL, while the Joffre Extraction Plant processed an average 61 MMscf per day to produce 3,536 barrels per day of NGL.

Financial Summary

Taylor's third quarter 2006 Net Operating Income was a record $16.2 million, an increase of 30 percent from the third quarter of 2005 and an increase of 8 percent from last quarter.



Net Operating Income
---------------------------------------------------------------------------
Three Months ended Nine Months ended
September 30 September 30
(in thousands of dollars) 2006 2005 2006 2005
---------------------------------------------------------------------------

Natural gas liquids sales $ 48,065 $ 47,666 $ 148,193 $ 112,728
Fee income 13,842 14,120 42,132 33,915
---------------------------------------------------------------------------
61,907 61,786 190,325 146,643
---------------------------------------------------------------------------

Shrinkage gas 35,720 39,598 115,301 91,548
Operating costs 10,037 9,791 29,561 27,087
Overhead recovery fees - - - 965
---------------------------------------------------------------------------
45,757 49,389 144,862 119,600
---------------------------------------------------------------------------

Net Operating Income $ 16,150 $ 12,397 $ 45,463 $ 27,043
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The revenue component of Net Operating Income was $61.9 million for the three months ended September 30, 2006, which was comparable to the same quarter in 2005.

The expense component of Net Operating Income was $45.8 million for the three months ended September 30, 2006, a seven percent decrease from the same quarter in 2005. The decrease is attributable to the reduced cost for shrinkage gas, which averaged $5.39 per GJ during the quarter compared to $8.78 per GJ in the same quarter last year. Shrinkage gas is initially paid by Taylor and then recovered from the purchasers of Taylor's NGL.

Outlook

Consistent with the Partnership's mandate, management is focusing on growth through projects and acquisitions that will diversify Taylor's asset base and increase Net Operating Income and Cash Available for Distribution.

The outlook for the Partnership's extraction plants is strongly influenced by NGL margin. The margin in NGL extraction continues to be at historically high levels. Natural gas prices are recently showing strength as focus shifts from the level of storage to the influence of winter weather on demand. As a result, NGL margins, while still very strong, are trending down.

Management is working with producers at both the RET Complex and the Harmattan Complex to tie in incremental natural gas for processing. The decline in natural gas prices since late 2005 has deferred natural gas exploration and development activities of many industry participants. However, activity in the Harmattan Complex capture area has not followed this trend. Approximately 127 drilling licences have been issued year-to-date compared to 76 licences for the same period in 2005. Year-to-date drilling activity in the RET Complex capture area is lagging 2005 but has surged in third quarter with approximately 35 locations licensed, up 45 percent from the activity level observed in the first quarter and up 35 percent from the second quarter of this year.

During the third quarter, Taylor filed an application with the Alberta Energy and Utility Board and continued public consultation on a project that will bring rich, sweet natural gas from TransCanada's Alberta system to the Harmattan Complex for processing to recover ethane, propane, butane and condensate. Upon approval by the regulator, construction will commence, requiring approximately 12 months to complete. The project, as currently envisioned, will cost in the range of $70 million to $90 million. For more information, please refer to the following page on Taylor's website:
http://www.taylorngl.com/HarmattanCochranePipeline.htm.

On October 31, 2006, the Government of Canada announced a proposal to tax income distributed by flow-through entities (FTEs), including publicly-traded limited partnerships, beginning 2011. In determining income that will be subject to the proposed tax, partnerships will be able to claim capital cost allowance (CCA) and other deductions. To the extent that income can be sheltered by CCA and other deductions, distributions will be characterized as “return of capital” and will be treated as a reduction of the cost of the unitholder’s investment.

At September 30, 2006, Taylor has approximately $181 million of undepreciated capital cost and other deductions. Management will monitor the Government’s proposal and adopt strategies that maximize unitholder value.

Critical Accounting Policies and Estimates

In the preparation of the Partnership's consolidated financial statements, management has made estimates that affect the recorded amounts of certain assets, liabilities, revenues and expenses. All estimates are adjusted for events that are known to have had a significant effect on the current quarter's operations, such as scheduled or unscheduled plant shutdowns. Given the amount of historical data available for the Partnership's NGL pipelines, the Younger Extraction Plant, the Joffre Extraction Plant, the RET Complex and the Harmattan Complex, management has been able to make these estimates with a high degree of accuracy. There are no known trends, events or uncertainties to indicate that actual results will vary significantly from the estimates used for the quarter ended September 30, 2006, nor would any expected variance have a material effect on the financial condition of the Partnership. Taylor's significant accounting policies and estimate methodologies, as disclosed in the Partnership's Annual Report for the year ended December 31, 2005, have not changed significantly.

Cash Distributions

Cash Available for Distribution was a record $11.2 million during the third quarter of 2006. Of this amount, Taylor distributed $7.9 million or $0.185 per unit to unitholders compared to $7.6 million or $0.1775 per unit during the same period in 2005.

For the three months ended September 30, 2006, Funds Provided by Operations was a record $12.7 million. Of these funds, the Partnership invested $0.4 million in projects to sustain the Partnership's assets and retained $4.4 million to fund the 2005 and 2006 LTIP awards, support future distributions, repay debt and fund growth initiatives.

Consistent with Taylor's accounting treatment of the 2005 LTIP award, Cash Available for Distribution has been reduced by the estimated value of the 2006 LTIP award. The actual value of the 2006 LTIP award will be based on full-year 2006 results and is subject to the approval of the Board of Directors.

During the nine months ended September 30, 2006 Taylor generated $32.0 million of Cash Available for Distribution, an increase of 55 percent over the same period in 2005. On a per weighted-average unit basis, Cash Available for Distribution was $0.753 per unit for the first nine months of 2006 compared to $0.541 per unit in the prior year's period.



Cash Available for Distribution
---------------------------------------------------------------------------
Three Months ended Nine Months ended
September 30 September 30
(in thousands of dollars) 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash provided by operations $ 10,108 $ 9,240 $ 29,991 $ 13,928
Add (deduct) change in
non-cash working capital 2,621 (22) 5,460 (854)
---------------------------------------------------------------------------
Funds Provided by Operations (1) 12,729 9,218 35,451 13,074
Management reorganization
costs (2) - - - 7,516
Capitalized operating
results (3) - - - 720
Reserve for Future
Commitments (4) (1,083) - (2,603) -
Sustaining Capital (5) (438) (96) (798) (591)
---------------------------------------------------------------------------

Cash Available for Distribution $ 11,208 $ 9,122 $ 32,050 $ 20,719
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Cash Available for Distribution
per unit $ 0.263 $ 0.215 $ 0.753 $ 0.541
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Cash Distributed
---------------------------------------------------------------------------

Three Months ended Nine Months ended
(in thousands of dollars September 30 September 30
except per unit amounts) 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash Available for Distribution $ 11,208 $ 9,122 $ 32,050 $ 20,719
Working capital returned
(withheld) (3,336) (1,572) (8,863) (1,184)
---------------------------------------------------------------------------
Cash distributed $ 7,872 $ 7,550 $ 23,187 $ 19,535
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Cash distributions paid
per unit $ 0.1850 $ 0.1775 $ 0.5450 $ 0.5150
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) Non-GAAP measure described as "cash provided by operations prior to
changes in non-cash working capital" as provided in the Consolidated
Statement of Cash Flow.

(2) On June 29, 2005, the Partnership acquired the interests and assets
from Taylor Management Company Inc. that related to the Partnership's
businesses.

(3) In accordance with GAAP, the operating results of the Harmattan Complex
from the effective date of the purchase, March 1, 2005, through March
21, 2005 were recorded as a $0.7 million reduction of the purchase
price. This amount is a contribution to Cash Available for
Distribution.

(4) Reserve for Future Commitments accounts for the timing difference
between the period in which the RSUs, awarded under the LTIP, were
earned and the GAAP treatment of the award. Reserve for Future
Commitments burdens the cost of RSUs against the period in which they
are earned, while GAAP applies the cost over the vesting period. The
change in the balance of the Reserve for Future Commitments for the
nine months ended September 30, 2006 is as follows:

Reserve for Future Commitments
-----------------------------------------------------------------------
(in thousands of dollars)
-----------------------------------------------------------------------

Balance, December 31, 2005 $ 1,240
Release of 2005 LTIP reserve during the period (502)
Reserve for the 2006 LTIP award during the period 3,105

-----------------------------------------------------------------------
Balance at September 30, 2006 $ 3,843
-----------------------------------------------------------------------

No funds or separate banking arrangements have been established for
this reserve.

(5) Sustaining Capital is defined as capital expenditures necessary to
maintain the safe and efficient operation of Taylor's facilities for
the long-term. Sustaining Capital items are not expensed due to the
long-term nature of these investments.


Results of Operations

Natural Gas Liquids Sales

NGL sales revenue is derived from the sale of production from the Younger and Joffre extraction plants and the Harmattan Complex. NGL sales revenue was $48.1 million in the third quarter of 2006 compared to $47.7 million for the same period in 2005. For the nine months ended September 30, 2006, NGL sales revenue was $148.2 million compared to $112.7 million for the same period in 2005. The increase in NGL sales was primarily the result of higher NGL sales prices and the full-year contribution of NGL sales from the Harmattan Complex. During the third quarter of 2006, the Partnership's NGL sales averaged 19,722 barrels per day compared to 17,315 barrels per day in the comparable quarter of 2005. NGL sales during the third quarter were slightly less than the second quarter as a result of maintenance conducted in September at the Harmattan Complex and Younger Extraction Plant which required the curtailment of production for a period of seven and six days, respectively.

NGL sales revenue at the Younger Extraction Plant, according to the NGL Purchase Agreement with Provident Energy Inc. (Provident), includes recovery of feedstock and operating costs, a return-on-capital derived fixed fee and a 50 percent profit share based on both an operating cost hurdle (Operating Pool) and NGL margin (Marketing Pool). The Marketing Pool is the Partnership's upside exposure to NGL commodity prices. The Marketing Pool is the difference between the sales revenue received by Provident upon the final sale of the NGL acquired from Taylor at the Younger Extraction Plant and all costs. A key feature of the Marketing Pool is that deficiencies are not charged to the Partnership, but are carried forward and recovered from future Marketing Pool revenue. Strong NGL margins realized during the third quarter of 2006 contributed to Marketing Pool proceeds of $3.5 million.

NGL sales revenue at the Joffre Extraction Plant includes a return-on-capital derived fixed fee and recovery of operating costs attributable to ethane production as defined by the Ethane Supply Agreement with NOVA Chemicals, plus the revenue received from the sale of propane, butane and condensate (collectively know as C3+). NGL sales revenue was augmented by $0.1 million as result of settling the components of the NGL margin hedge for the month of September.

NGL sales revenue at the Harmattan Complex includes the revenue from the sale of the Partnership's ethane, frac oil and C3+ production.

The largest component of NGL sales revenue is the recovery of natural gas feedstock cost (or shrinkage gas) incurred at the Younger Extraction Plant and Harmattan Complex. The AECO daily natural gas price, which is indicative of the Partnership's actual natural gas feedstock purchase price, averaged $5.39 per gigajoule (GJ) during the third quarter of 2006 versus $8.78 per GJ during the same period in 2005. AECO daily natural gas price averaged $6.09 per GJ during the nine months ended September 30, 2006 compared to $7.42 per GJ for the same period in 2005.

Fee Income

Fee income consists of revenue received from processing third-party natural gas at the RET Complex, Harmattan Complex and the Younger Extraction Plant, transportation fees from the use of the Ethylene Delivery System (EDS) and the Joffre Feedstock Pipeline (JFP) and overhead recoveries. Overhead recoveries are those charges applied to operating and capital expenditures pursuant to the operating agreements with the owners at each of the facilities that the Partnership operates.

Fee income for the three months ended September 30, 2006 was $13.8 million compared to $14.1 million in the same 2005 period. The small decrease was a result of reduced natural gas volumes processed at the Harmattan Complex in September due to maintenance activities.

Fee income for the nine months ended September 30, 2006 was $42.1 million compared to $33.9 million in the same 2005 period. The significant increase was a result of full-year contributions from the Harmattan Complex and additional JFP transportation fee revenues.

Shrinkage Gas Expense

The cost of natural gas feedstock that is consumed in the extraction of NGL, commonly known as shrinkage gas expense, was $35.7 million for the third quarter of 2006 compared to $39.6 million in the same period in 2005. The current quarter decline is mainly the result of lower natural gas prices which averaged $5.39 per GJ compared to $8.78 per GJ in the same quarter last year. Also contributing to the decline was reduced shrinkage gas requirements for the Harmattan Complex and Younger Extraction Plant as a result of maintenance activities conducted in September. For the nine months ended September 30, 2006 shrinkage gas expense was $115.3 million compared to $91.5 million in the first nine months of 2005. The increase was primarily the result of increased NGL production, specifically the increased volumes produced at the Harmattan Complex.

During the quarter, an additional $0.2 million was applied to the cost of shrinkage gas expense as result of settling the natural gas component of the NGL margin hedge for the month of September.

Operating Costs

Operating costs in the third quarter of 2006 were $10.0 million, which was comparable to the third quarter 2005 of $9.8 million and the second quarter 2006 of $10.0 million. Operating costs for the nine months ended September 30, 2006 were $29.6 million compared to $27.1 million for the same period in 2005. The increase was the result of the addition of the Harmattan Complex and JFP in March 2005.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2006 was $4.4 million and $13.2 million, respectively, compared to $4.4 million and $10.3 million for the same periods in 2005. The year-to-date increase largely reflects depreciation, amortization and accretion related to JFP and the Harmattan Complex, which were first included in March 2005.

Interest Expense

Interest costs in the third quarter of 2006 were $2.2 million compared to $2.0 million in the same period in 2005. During the nine months ended September 30, 2006 interest costs were $6.3 million compared to $4.4 million in the same period in 2005. The year-to-date increase is a result of higher debt levels and higher comparative interest rates. The average annual interest rate on the Partnership's debt facilities and convertible debentures for the nine months ended September 30, 2006 was 5.7 percent, compared to 5.1 percent in the same period in 2005.

Administration Costs

Administration costs in the third quarter of 2006 were $1.4 million compared to $1.3 million in the same quarter of 2005. For the nine months ended September 30, 2006, administration costs were $4.3 million compared to $2.4 million in the same period in 2005. The year-to-date increase over 2005 was largely the result of changes in the relationship between Taylor Management Company Inc. (the Manager) and the Operating Partnerships that occurred following the management reorganization transaction of June 29, 2005.

Prior to June 29, 2005, according to the terms of the 2001 Administration Agreement, the Partnership recorded the payment of overhead recoveries to the Manager as an expense, which reduced administration costs charged by the Manager to the Partnership. With the assignment of the 2001 Administration Agreement from the Manager to the Partnership, the Partnership no longer pays overhead recovery fees to the Manager, therefore, administration expenses are no longer reported net of overhead recovery fees.

For comparative purposes, the sum of administration expenses and overhead recovery fees should be considered. For the nine months ended September 30, 2006, this amount was $4.3 million (2005 - $3.4 million). The increase from 2005 was a result of additional costs incurred in managing the Partnership's growing asset base and amortization of the 2005 LTIP award. The GAAP treatment of the 2005 LTIP award has resulted in $0.7 million being expensed during the nine months ended September 30, 2006 based on September's closing unit price of $9.55 per unit. As an offset to this charge, $0.5 million has been released into year-to-date Cash Available for Distribution from the Reserve for Future Commitments (discussed under Cash Distributions).

Mark-to-Market Gain on Financial Instruments

The Partnership uses derivative financial instruments such as collars and swaps to manage exposure to fluctuations in interest rates, electricity prices, natural gas prices and NGL margin.

The aggregate fair value of the interest rate swaps at September 30, 2006, based on the then current market price, was an unrealized liability of $0.3 million (December 31, 2005 - $0.3 million liability).

The Partnership holds electricity swap agreements, which commenced January 1, 2006 and expire December 31, 2008, as disclosed in the Partnership's 2005 annual consolidated financial statements and notes. The fair value of the electricity rate swaps at September 30, 2006, based on the then current market price, was an unrealized asset of $0.5 million (December 31, 2005 - $1.2 million asset).

The fair value of the natural gas price swap at September 30, 2006, based on the then current market price, was an unrealized liability of $65,000 (December 31, 2005 - not applicable).

On July 28, 2006, the Partnership entered into a series of swaps, which have the effect of fixing NGL margin at approximately $20.50 per barrel for 15,900 barrels of C3+ per month. The swap arrangements commence September 1, 2006 and expire on December 31, 2006. For each monthly settlement, the Partnership will apply the cash payment, or receipt, for NGL against income statement line item "natural gas liquids sales" and for natural gas against income statement line item "shrinkage gas". The settlement of the September series of swaps resulted in a net payment by Taylor of $0.1 million. The fair value of the series of swaps at September 30, 2006, based on the then current market price, was an unrealized asset of $19,000 (December 31, 2005 - not applicable).

Management Fees

On June 29, 2005, the Manager assigned the 2001 Administration Agreement to the Partnership. As a result, management fees are no longer paid by the Partnership.

Limited Partner Distributions

On June 29, 2005, the Manager converted its Expansion Units of Taylor Gas Liquids Limited Partnership (TGLLP) into Partnership units. As a result, distributions are no longer paid by TGLLP to the Manager.

Net Income

Net income was $7.3 million in the three months ended September 30, 2006, compared to $5.1 million in the same period in 2005. In the nine months ended September 30, 2006 net income was $21.0 million, compared to $1.6 million in the same period in 2005. The increase in net income was largely the result of the one-time management reorganization costs in June 2005 and full-year inclusion of the Harmattan Complex in 2006.

Capital Expenditures

The Partnership funded capital expenditures of $1.4 million during the third quarter of 2006, of which $1.0 million was expended on several growth projects and $0.4 million was designated as Sustaining Capital.

Equity

At September 30, 2006, Taylor had 42,553,490 Partnership units outstanding (December 31, 2005 - 42,535,240). The increase was the result of 18,250 options being exercised. The following table summarizes information about the Unit Option Plan as at September 30, 2006 and 2005:



Unit Option Plan
---------------------------------------------------------------------------
Nine Months ended Nine Months ended
September 30 September 30
2006 2005
Average Average
Exercise Exercise
Price per Price per
Options option Options option
---------------------------------------------------------------------------

Outstanding, beginning of
period 419,250 $ 7.94 181,500 $ 6.01

Granted 13,500 9.79 129,500 9.04
Exercised (18,250) 6.47 (38,000) 4.80
Expired (17,500) 8.58 (20,000) 4.65

---------------------------------------------------------------------------
Outstanding, end of period 397,000 $ 8.04 253,000 $ 7.85
Exercisable, end of period 150,750 $ 7.65 85,000 $ 7.04
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Financial Position

The following table outlines significant changes in the consolidated
balance sheets that occurred between December 31, 2005 and September 30,
2006:

Increase
($000s) (Decrease) Explanation
---------------------------------------------------------------------------

Cash $ (3,538) Refer to Consolidated Statement of Cash
Flow.

Accounts receivable 2,331 Increase a result of higher revenues.

Capital assets (3,960) Decrease a result of depreciation and
amortization of $10.5 million offset by
$6.5 million in capital additions since
December 2005.

Intangible assets (2,198) Decrease a result of accumulated
amortization since December 2005.

Accounts payable (3,348) Decrease a result of lower payables for
shrinkage gas due to lower natural
gas prices since December 2005.

Long-term debt (4,000) Excess Funds Provided by Operations used to
reduce revolving credit facility.

Unitholders' $ (2,077) Decrease largely a result of unitholders'
equity distributions declared of $23.3
million, offset by net income earned of
$21.0 million since December 2005.

---------------------------------------------------------------------------

Liquidity and Capital Resources

The following table summarizes the changes in cash flow for the nine months
ended September 30, 2006 compared to the nine months ended September 30,
2005:

($000s) 2006 2005 Explanation
---------------------------------------------------------------------------
Cash, beginning of
period $ 4,406 $ 5,409

Cash provided by
(used in):

Operating
activities 29,991 13,928 During the first nine months of
2006, Funds Provided by
Operations were $35.5 million
compared to $13.1 million in 2005.
2006 year-to date includes a full
period of Harmattan Complex and
JFP operations.

During the first nine months of
2005, cash was reduced by $7.5
million to provide for one-time
management reorganization costs
and planned turnaround costs of
$2.4 million for the Harmattan
Complex and the Younger and Joffre
extraction plants. Offsetting
these amounts was cash provided by
EDS and JFP and the addition
of Harmattan Complex operations,
which commenced March 22, 2005.

Financing
activities (27,069) 188,053 During the first nine months of
2006, cash distributions of $23.2
million were paid and long-term
debt was reduced by $4.0 million,
offset marginally by funds
received on exercise of options.

During the first nine months of
2005, cash was provided mainly
from a unit offering that raised
$113.9 million net of costs, a
convertible debentures offering
that raised $47.9 million net of
costs and long term debt drawings
of $49.7 million. These funds were
used for the Harmattan Complex
acquisition, redemption of the
$4.0 million debenture issued by
the previous owners of the
Harmattan Complex and JFP
construction expenditures.
Distributions paid during the
period were $19.5 million.

Investing
activities (6,430) (205,797) During the first nine months of
2006, the reduction in cash was
a result of $6.5 million used for
funding capital expenditures in
JFP and other capital projects at
the Harmattan Complex, RET Complex
and Younger Extraction Plant plus
$0.1 million of non-cash working
capital for the above capital
projects.

During the first nine months of
2005, the reduction in cash was a
result of $177.3 million used for
the Harmattan Complex acquisition,
$19.1 million for funding the
construction of JFP and other
capital projects at the RET
Complex and Younger Extraction
Plant, plus $9.4 million of
non-cash working capital for the
construction of JFP.

Effect of exchange
rate changes
on cash (30) (29) Change is a result of unrealized
foreign exchange loss (gain)
on U.S.-dollar denominated cash
balances.
---------------------------------------------------------------------------

Cash, end of
period $ 868 $ 1,564
---------------------------------------------------------------------------


Working Capital and Cash Requirements

The Partnership had working capital of $7.1 million at September 30, 2006 compared to $5.4 million at December 31, 2005.

As a result of the terms of the Partnership's commercial contracts, a significant portion of cash collections occur simultaneously with cash payments, thereby minimizing the Partnership's requirement to maintain a significant working capital position. Any timing differences, whether short- or long-term, are managed with working capital or existing debt facilities.

With the exception of those items disclosed, there are no known trends, events or uncertainties to indicate any impairment in the sources or uses of cash that would have a material effect on the financial condition of the Partnership.

Debt Facilities

At September 30, 2006, the Partnership had available debt facilities of $130.0 million, consisting of a $120 million revolving credit facility and a $10 million operating facility. At the end of the third quarter, $87.0 million had been drawn on the $120.0 million revolving credit facility, a reduction of $2.0 million from the end of the second quarter. No amount has been drawn against the operating facility; however, the amount available under this facility has been reduced by $0.8 million to support outstanding letters of credit.

On June 16, 2006, the Partnership received approval from all credit syndicate members to extend the revolving facility renewal date from June 30, 2006 to June 29, 2007, at which time it can be extended at the lenders' option for another 364 days. If the revolving facility is not extended, the amount drawn is fully repayable on June 29, 2008.

Proposed GST Assessment Update

On February 1, 2006, the Partnership received a letter from the Canada Revenue Agency (CRA) outlining a proposed assessment related to Goods and Services Tax (GST) as disclosed in note 17 of the 2005 annual consolidated financial statements and notes. On October 13, 2006, after a series of letters were exchanged between the CRA, the Partnership and the Partnership's legal counsel, the Partnership received a letter from the CRA outlining its intent to issue a notice of assessment to disallow Input Tax Credits claimed by the Partnership in the amount of $1.2 million, including interest and penalties. The CRA asserts that the relevant costs incurred by the Partnership do not relate to the commercial activities of the Operating Partnerships for the purposes of the Excise Tax Act. The Partnership has not recorded the assessment in its financial statements and continues to take the position that the Input Tax Credits have been claimed in accordance with the law.

Risk Factors and Risk Management

Readers of the Partnership's interim report should carefully consider the risks described under ''Risk Factors'' in the Partnership's Annual Information Form and as disclosed in the Partnership's Annual Report for the year ended December 31, 2005. The Partnership's business and commodity price risks remain substantially unchanged from December 31, 2005.

On July 28, 2006, the Partnership entered into a series of financial swaps to fix the NGL margin on a portion of the Partnership's C3+ production. As a result, a portion of the Partnership's exposure to commodity-based price volatility has been mitigated.

CORPORATE INFORMATION

The Partnership owns and operates the RET Complex, the Harmattan Complex and the Joffre Extraction Plant, all in Alberta, and the Younger Extraction Plant in British Columbia. The Partnership also owns two NGL pipelines, the Ethylene Delivery System and the Joffre Feedstock Pipeline, both of which move products between Joffre, Alberta and Fort Saskatchewan, Alberta. The Joffre and Younger plants are NGL extraction facilities that produce ethane, propane, butane and condensate. The RET Complex and the Harmattan Complex are natural gas processing facilities that provide services to oil and natural gas producers.

The Partnership is organized in accordance with the terms and conditions of a limited partnership agreement which provides that no Partnership units may be transferred to, among other things, a person who is a "non-resident" of Canada or a partnership which is not a "Canadian partnership" for purposes of the Income Tax Act (Canada).

Taylor NGL Limited Partnership units and convertible debentures trade on the Toronto Stock Exchange (TSX) under the symbol TAY.UN and TAY.DB, respectively.



TAYLOR NGL LIMITED PARTNERSHIP
Consolidated Balance Sheets
(Stated in thousands of dollars)

---------------------------------------------------------------------------
September 30 December 31
2006 2005
---------------------------------------------------------------------------
(unaudited) (audited)

Assets

Current assets:
Cash and cash equivalents $ 868 $ 4,406
Accounts receivable 19,971 17,640
Prepaid expenses and interest 1,105 1,414
-------------------------------------------------------------------------
21,944 23,460

Market value of financial instruments (note 10) 145 941
Capital assets (note 2) 393,102 397,062
Intangible assets (note 2) 19,826 22,024
Deferred financing costs 1,512 1,804
---------------------------------------------------------------------------
$ 436,529 $ 445,291
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities and Unitholders' Equity

Current liabilities:
Accounts payable and accrued liabilities $ 12,167 $ 15,515
Unitholders' distributions payable 2,660 2,552
-------------------------------------------------------------------------
14,827 18,067

Long-term debt (note 3) 87,000 91,000
Convertible debentures (note 4) 48,282 47,970
Asset retirement obligations (note 5) 3,884 3,641
---------------------------------------------------------------------------
153,993 160,678
---------------------------------------------------------------------------

Unitholders' equity (note 6):
Unitholders' capital 314,462 314,344
Convertible debentures 2,325 2,325
Contributed surplus 252 132
Deficit (34,503) (32,188)
-------------------------------------------------------------------------
282,536 284,613
---------------------------------------------------------------------------
$ 436,529 $ 445,291
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


TAYLOR NGL LIMITED PARTNERSHIP
Consolidated Statement of Income and Deficit
(Stated in thousands of dollars except per unit amounts)

---------------------------------------------------------------------------
Three Months ended Nine Months ended
September 30 September 30
(unaudited) 2006 2005 2006 2005
---------------------------------------------------------------------------

Revenue:
Natural gas
liquids sales $ 48,065 $ 47,666 $ 148,193 $ 112,728
Fee income 13,842 14,120 42,132 33,915
Other 42 2 123 27
-------------------------------------------------------------------------
61,949 61,788 190,448 146,670
-------------------------------------------------------------------------

Expenses:
Shrinkage gas 35,720 39,598 115,301 91,548
Operating costs 10,037 9,791 29,561 27,087
Depreciation,
amortization and
accretion 4,404 4,351 13,212 10,343
Interest 2,241 1,954 6,280 4,360
Administration 1,363 1,336 4,287 2,428
Mark-to-market loss
(gain) on financial
instruments (note 10) 854 (371) 797 203
Foreign exchange
loss (gain) (1) 39 30 36
Overhead recovery fees - - - 965
Management reorganization
costs - - - 8,132
-------------------------------------------------------------------------
54,618 56,698 169,468 145,102
-------------------------------------------------------------------------

Net income 7,331 5,090 20,980 1,568

Deficit, beginning
of period (33,855) (29,667) (32,188) (13,301)

Unitholders'
distributions declared (7,979) (7,656) (23,295) (20,500)
---------------------------------------------------------------------------
Deficit, end of period $ (34,503) $ (32,233) $ (34,503) $ (32,233)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Net income per
Partnership
unit (note 8):
Basic $ 0.17 $ 0.12 $ 0.49 $ 0.04
Diluted $ 0.17 $ 0.12 $ 0.49 $ 0.04
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


TAYLOR NGL LIMITED PARTNERSHIP
Consolidated Statement of Cash Flow
(Stated in thousands of dollars)

---------------------------------------------------------------------------
Three Months ended Nine Months ended
September 30 September 30
(unaudited) 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash provided by (used in):

Operations:
Net income $ 7,331 $ 5,090 $ 20,980 $ 1,568
Depreciation,
amortization and
accretion 4,404 4,351 13,212 10,343
Mark-to-market loss
(gain) on financial
instruments 854 (371) 797 203
Accretion of convertible
debentures discount 104 104 312 220
Partnership unit-based
compensation 36 25 120 95
Unrealized foreign
exchange loss - 19 30 29
Non-cash management
reorganization costs - - - 616
-------------------------------------------------------------------------
12,729 9,218 35,451 13,074

Change in non-cash
working capital (2,621) 22 (5,460) 854
-------------------------------------------------------------------------
10,108 9,240 29,991 13,928
-------------------------------------------------------------------------

Financing:
Unitholders'
distributions paid (7,872) (7,550) (23,187) (19,535)
Long-term debt (2,000) 2,000 (4,000) 49,680
Units issued for cash,
net of issue costs - - 118 114,038
Convertible debentures,
net of issue costs - - - 47,870
Debenture paid on
Acquisition - - - (4,000)
-------------------------------------------------------------------------
(9,872) (5,550) (27,069) 188,053
-------------------------------------------------------------------------

Investments:
Capital expenditures (1,381) (2,733) (6,519) (19,116)
Change in non-cash
investing working
capital 211 - 89 (9,400)
Acquisition - - - (177,281)
-------------------------------------------------------------------------
(1,170) (2,733) (6,430) (205,797)
-------------------------------------------------------------------------

Effect of exchange rate
changes on cash - (19) (30) (29)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Change in cash and
cash equivalents (934) 938 (3,538) (3,845)
Cash and cash equivalents,
beginning of period 1,802 626 4,406 5,409

---------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 868 $ 1,564 $ 868 $ 1,564
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Interest paid on a cash basis during the three months and nine months ended
September 30, 2006 was $2.8 million and $7.0 million, respectively(2005 -
$0.3 million and $1.7 million, respectively).

See accompanying notes to consolidated financial statements.


TAYLOR NGL LIMITED PARTNERSHIP
Notes to the Consolidated Financial Statements
Nine months ended September 30, 2006 and 2005 (unaudited)
(all tabular amounts are stated in thousands of dollars except unit
amounts)


1. Basis of presentation

The interim consolidated financial statements of Taylor NGL Limited Partnership (the "Partnership") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2005. The disclosure provided below is incremental to the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Partnership's annual report for the year ended December 31, 2005.



2. Capital assets

---------------------------------------------------------------------------
September 30 December 31
2006 2005
---------------------------------------------------------------------------

Property, plant and equipment $ 352,661 $ 348,446
Pipelines 87,424 85,123
Accumulated depreciation (46,983) (36,507)
---------------------------------------------------------------------------
393,102 397,062
---------------------------------------------------------------------------

Intangible assets 24,761 24,761
Accumulated amortization (4,935) (2,737)
---------------------------------------------------------------------------
19,826 22,024
---------------------------------------------------------------------------

---------------------------------------------------------------------------
$ 412,928 $ 419,086
---------------------------------------------------------------------------
---------------------------------------------------------------------------


3. Long-term debt

At September 30, 2006, the Partnership's $120 million revolving credit facility ("Revolving Facility") was drawn by $87 million (December 31, 2005 - $91 million). During the second quarter of 2006, the Revolving Facility was extended for a further 364-day period commencing June 30, 2006 and expiring on June 29, 2007, at which time it can be extended at the lenders' option for another 364 days. If the Revolving Facility is not extended, the amount drawn is fully repayable on June 29, 2008.

The Partnership also has a $10 million operating facility. As at September 30, 2006, the amount available under this facility was reduced by $0.8 million to support outstanding letters of credit.



4. Convertible debentures

---------------------------------------------------------------------------
Balance, December 31, 2005 $ 47,970

Accretion of discount to September 30, 2006 312
---------------------------------------------------------------------------

Balance, September 30, 2006 $ 48,282
---------------------------------------------------------------------------
---------------------------------------------------------------------------

At September 30, 2006, the convertible debentures had an estimated fair
value of $50.8 million.

5. Asset retirement obligations

---------------------------------------------------------------------------
Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------

Asset retirement obligations,
beginning of period $ 3,641 $ 1,340
Additions due to acquisitions
during the period - 2,044
Accretion expense 243 257
---------------------------------------------------------------------------

Asset retirement obligations,
end of period $ 3,884 $ 3,641
---------------------------------------------------------------------------
---------------------------------------------------------------------------

6. Unitholders' equity

---------------------------------------------------------------------------
September 30 December 31
2006 2005
---------------------------------------------------------------------------

Unitholders' capital $ 314,462 $ 314,344
Accumulated earnings 76,805 55,825
Convertible debentures 2,325 2,325
Contributed surplus 252 132
Accumulated distributions (111,308) (88,013)
---------------------------------------------------------------------------

$ 282,536 $ 284,613
---------------------------------------------------------------------------
---------------------------------------------------------------------------


---------------------------------------------------------------------------
Number of
units Amount
---------------------------------------------------------------------------

Balance, December 31, 2005 42,535,240 $ 284,613

Net income for the nine months ended
September 30, 2006 20,980
Unitholders' distributions declared (23,295)
Units issued on exercise of options 18,250 118
Contributed surplus 120
---------------------------------------------------------------------------

Balance, September 30, 2006 42,553,490 $ 282,536
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Partnership unit-based compensation of $120,000 was expensed during the
nine months ended September 30, 2006 with a corresponding increase in
contributed surplus.

7. Long-term Incentive Plan

---------------------------------------------------------------------------
Number of Restricted
Share Units (RSUs)
---------------------------------------------------------------------------

Balance, December 31, 2005 -

Awarded during the period 135,397
Cash distribution equivalent RSUs earned during
period 7,274
Cancelled during the period (351)
---------------------------------------------------------------------------

Balance, September 30, 2006 142,320
---------------------------------------------------------------------------
---------------------------------------------------------------------------

The compensation cost recorded for Restricted Share Units for the nine
months ended September 30, 2006 was $0.7 million (2005 - nil) based on the
market price of a Partnership unit on September 30, 2006.

8. Income per Partnership unit

The following table summarizes the computation of net income per
Partnership unit:

---------------------------------------------------------------------------
Three months ended Nine months ended
Sep 30 Sep 30
2006 2005 2006 2005
---------------------------------------------------------------------------

Numerator:
Numerator for basic
income per unit $ 7,331 $ 5,090 $ 20,980 $ 1,568
Convertible debentures
interest 733 719 2,186 1,528
Accretion of convertible
debentures discount 104 104 312 220
---------------------------------------------------------------------------

Numerator for diluted
income per unit $ 8,168 $ 5,913 $ 23,478 $ 3,316
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Denominator:
Weighted-average
denominator for basic
units 42,553,490 42,531,490 42,546,146 32,288,926
Convertible debentures 4,828,019 4,828,019 4,828,019 3,398,107
Dilutive unit options 72,758 44,868 83,157 52,272
---------------------------------------------------------------------------

Denominator for diluted
income per unit 47,454,267 47,404,377 47,457,322 41,739,305
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Basic income per unit $ 0.17 $ 0.12 $ 0.49 $ 0.04
Diluted income per unit $ 0.17 $ 0.12 $ 0.49 $ 0.04
---------------------------------------------------------------------------
---------------------------------------------------------------------------

9. Pension Plan

The Partnership maintains pension plans with defined benefit provisions.
The expenses associated with these plans are as follows:

---------------------------------------------------------------------------
For the nine months ended Younger Harmattan
September 30, 2006 Plan Plan
---------------------------------------------------------------------------

Current service cost $ 143 $ 142
Interest cost on accrued benefit
obligation 84 211
Less expected return on plan assets (91) (200)
Amortization of transitional (asset)
obligation 1 (2)
Amortization of net actuarial (gain) loss - 2

---------------------------------------------------------------------------
Pension cost recognized during period $ 137 $ 153
---------------------------------------------------------------------------
---------------------------------------------------------------------------


At September 30, 2006, the Partnership had an accrued pension obligation of $0.1 million which has been included in accounts payable and accrued liabilities.

10. Financial instruments

Financial instruments added by the Partnership since December 31, 2005 are listed below.

Interest rates

On February 22, 2006, the Partnership entered into an interest rate swap on a principal amount of $20 million, whereby the Partnership receives a floating rate and pays a fixed rate of 4.34%. The swap commenced on February 22, 2006 and matures March 1, 2010.

Also on February 22, 2006, the Partnership entered into an interest rate swap on a principal amount of $10 million, whereby the Partnership receives a floating rate and pays a fixed rate of 4.13%. The swap commenced on February 22, 2006 and matures January 31, 2007.

The interest rate swaps have early settlement options, in whole or in part, of the principal amounts, which are currently in effect and exist until their respective maturity date. If either party exercises this option, the derivative financial instrument will be settled at the then current market price.

Fuel gas rates

On March 6, 2006, the Partnership entered into a natural gas rate swap for 500 GJ per day based on the monthly AECO spot price, whereby the Partnership receives a floating rate and pays a fixed rate of $6.84 per GJ. The swap commenced on April 1, 2006 and expires on December 31, 2006.

The natural gas rate swap has an early settlement option, in whole or in part, which are currently in effect and exist until their respective maturity date. If either party exercises this option, the derivative financial instrument will be settled at the then current market price.

NGL margin

On July 28, 2006, the Partnership entered into a series of financial swap arrangements, which have fixed the NGL margin at an effective rate of approximately $20.50 per barrel on 15,900 barrels of propane-plus per month. The swap arrangements commence September 1, 2006 and expire on December 31, 2006.



The NGL margin swap is comprised of:

---------------------------------------------------------------------------
Quantity
Price per month
---------------------------------------------------------------------------

Sell:
Propane (Mt. Belvieu) US$1.1495 per US gallon 12,000 barrels
Normal butane (Mt. Belvieu) US$1.3295 per US gallon 2,000 barrels
Iso-butane (Mt. Belvieu) US$1.3320 per US gallon 900 barrels
Condensate (WTI) US$75.09 per barrel 1,000 barrels
US-dollars CAD 1.1246 per USD US$365,000

Buy:
Natural gas (AECO) US$7.16 per MMBTU 63,400 MMBTU
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The NGL margin swap has early settlement options, in whole or in part, which are currently in effect and exist until their respective maturity date. If either party exercises this option, the derivative financial instrument will be settled at the then current market price.

11. Contingencies

On October 13, 2006, subsequent to the quarter close, the Partnership received a letter from Canada Revenue Agency (CRA) outlining its intention to proceed to assess the Partnership related to Goods and Services Tax (GST), as disclosed in the Partnership's 2005 Annual Report. The Partnership maintains its original position that the Input Tax Credits have been properly claimed in accordance with the law. Accordingly, the Partnership has not recorded the assessment, interest or penalties in its financial statements.

Contact Information