CALGARY, Aug. 1 /PRNewswire-FirstCall/ -- PENN WEST ENERGY TRUST (TSX - PWT.UN; NYSE - PWE) is pleased to announce its results for the second quarter ended June 30, 2007.
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Operations
- Production averaged 126,599 boe per day in the second quarter of 2007
compared to 93,242 boe per day in the same period of 2006. The
previously announced fire at our Wildboy tank farm reduced reported
second quarter 2007 gas production by approximately 20 mmcf per day
(approximately 3,300 barrels of oil equivalent).
- Crude oil and NGL production averaged 70,923 barrels per day and
natural gas production averaged 334 mmcf per day in the second
quarter of 2007.
- Penn West invested $484 million on capital development that included
$351 million of net property acquisitions and drilled 13 net wells in
the second quarter with a success rate of 92 percent.
Financial
- Cash flow of $326 million ($1.37 per unit, basic) in the second
quarter of 2007 was 23 percent higher than cash flow of $265 million
($1.59 per unit, basic) realized in the second quarter of 2006,
mainly due to higher production as a result of the Petrofund merger
reflected from July 1, 2006 forward.
- The net loss in the second quarter of 2007 was $185 million
($0.77 per unit, basic) compared to net income of $221 million
($1.34 per unit, basic) in the second quarter of 2006, mainly due to
a $326 million future income tax charge taken to reflect the
enactment of the tax on income trusts (the "SIFT tax").
- In the absence of the charge to reflect the SIFT tax enactment, net
income for the second quarter and first half of 2007 would have been
$140 million ($0.59 basic per unit) and $237 million ($0.99 basic per
unit), respectively.
- After the acquisition of approximately 80 percent of the shares of C1
Energy Ltd. by July 23, 2007, a notice of extension was subsequently
mailed extending the offer to August 3, 2007.
- On May 31, 2007, Penn West Petroleum Ltd. issued US$475 million of
unsecured notes maturing in eight to 15 years on a private placement
basis in the United States. The Company used the proceeds of the
notes to repay a portion of the outstanding bank debt under its
credit facilities.
Distributions
- Penn West's Board of Directors recently resolved to keep our
distribution level at $0.34 per unit, per month, for the next
three months subject to current forecasts of commodity prices,
production and planned capital expenditures.
Distribution Tax
- In June 2007, the Government of Canada enacted the previously
announced tax on publicly traded income trusts. This resulted in the
accounting recognition of an additional $326 million future income
tax liability and a non-cash future income tax expense in the second
quarter of 2007. The tax enactment and the related charge against
income did not affect cash flow or distributions in the quarter and
is not expected to affect our distribution policies until 2011 at the
earliest. Penn West will remain active with various parties pursuing
a re-evaluation of the tax legislation and continues to review
various tax efficient structural alternatives.
Long-term Project Updates
- In the second half of 2007, in addition to ongoing geological and
engineering studies and pilot tests, Penn West plans to drill an
additional 19 horizontal wells and 14 stratigraphic test wells in its
Peace River Oil Sands project. We expect to complete the tie-in of
41 producing wells to recently constructed production facilities by
August 2007, to significantly increase netbacks by reducing trucking
costs. The previously announced acquisition of producing light oil
and natural gas properties, undeveloped lands, additional
infrastructure and all-weather roads in the project area will be
important in the development of the project area.
- During the second quarter, we continued to evaluate an integrated
approach to enhancing our light oil recovery rates from large, legacy
oil pools using miscible flooding with CO2 captured from heavy
industry gasification processes while at the same time helping to
sequester greenhouse gases. At our Pembina CO2 pilot project, we
plan to drill four horizontal wells in the third quarter which we
expect to be on-stream by the first quarter of 2008. We are de-
watering our four wells drilled to date at our South Swan Hills
coalbed methane pilot project and are assessing potential future
coalbed methane development programs in the area.
HIGHLIGHTS
Three months ended Six months ended
June 30 June 30
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($ millions, except
per unit and % %
production amounts) 2007 2006 change 2007 2006 change
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Financial
Gross revenues(1) $ 608.3 $ 452.5 34 $1,190.7 $ 886.4 34
Cash flow 326.2 264.7 23 637.5 507.9 26
Basic per unit 1.37 1.59 (14) 2.68 3.08 (13)
Diluted per unit 1.35 1.56 (13) 2.65 3.03 (13)
Net (loss) income (185.2) 220.5 (184) (88.9) 364.9 (124)
Basic per unit (0.77) 1.34 (157) (0.37) 2.22 (117)
Diluted per unit (0.77) 1.31 (159) (0.37) 2.18 (117)
Capital
expenditures, net 483.6 105.8 357 699.5 263.8 165
Long-term debt at
period-end 1,822.5 1,369.7 33 1,822.5 1,369.7 33
Distributions
paid(2) $ 243.1 $ 167.4 45 $ 485.2 $ 324.3 50
Operations
Daily production
Natural gas
(mmcf/d) 334.1 267.9 25 337.2 267.4 26
Light oil and NGL
(bbls/d) 49,635 29,974 66 49,372 30,755 61
Conventional
heavy oil
(bbls/d) 21,288 18,625 14 21,945 19,648 12
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Total production
(boe/d) 126,599 93,242 36 127,518 94,968 34
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Average sales price
Natural gas
($/mcf) $ 7.55 $ 6.14 23 $ 7.57 $ 7.12 6
Light oil and NGL
($/bbl) 65.24 71.96 (9) 62.39 66.93 (7)
Conventional
heavy oil
($/bbl) $ 42.45 $ 52.85 (20) $ 41.73 $ 41.29 1
Netback per boe
Sales price $ 52.63 $ 51.33 3 $ 51.35 $ 50.26 2
Risk management 0.03 2.00 (99) 0.16 1.30 (88)
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Net sales price 52.66 53.33 (1) 51.51 51.56 -
Royalties 9.82 9.45 4 9.72 9.59 1
Operating expenses 10.94 10.26 7 10.82 10.07 7
Transportation 0.52 0.60 (13) 0.53 0.64 (17)
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Netback $ 31.38 $ 33.02 (5) $ 30.44 $ 31.26 (3)
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The above information includes non-GAAP measures not defined under
generally accepted accounting principles, including cash flow and
netback. Cash flow is cash flow from operating activities before changes
in non-cash working capital, and asset retirement expenditures. Please
refer to the calculation of cash flow table on the first page of the
Management's Discussion and Analysis for a reconciliation of cash flow
from operating activities to cash flow. Barrels of oil equivalent (boe)
are based on six mcf of natural gas equalling one barrel of oil (6:1).
Netback is a per unit of production measure of operating margin used in
capital allocation decisions.
(1) Gross revenues include realized gains and losses on commodity
contracts.
(2) Includes distributions paid in trust units under the distribution
reinvestment plan.
DRILLING PROGRAM
Three months ended Six months ended
June 30 June 30
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2007 2006 2007 2006
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Gross Net Gross Net Gross Net Gross Net
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Natural gas 5 3 12 5 54 25 80 64
Oil 24 8 23 21 77 44 64 55
Dry 1 1 1 1 5 4 11 11
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30 12 36 27 136 73 155 130
Stratigraphic
and service 4 1 1 1 19 15 9 6
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Total 34 13 37 28 155 88 164 136
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Success Rate(1) 92% 96% 95% 92%
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(1) Success rate is calculated excluding stratigraphic and service wells.
UNDEVELOPED LANDS
As at June 30
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2007 2006 % change
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Gross acres (000s) 3,969 4,825 (18)
Net acres (000s) 3,470 4,305 (19)
Average working interest 87% 89% (2)
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FARM-OUT ACTIVITY
Three months ended Six months ended
June 30 June 30
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2007 2006 2007 2006
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Wells drilled on farm-out
lands(1) 16 26 106 54
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(1) Wells drilled on Penn West lands, including re-completions and re-
entries, by independent operators pursuant to farm-out agreements.
CORE AREA ACTIVITY
Net wells drilled for Undeveloped land
the six months ended as at June 30, 2007
Core Area June 30, 2007 (thousands of net acres)
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Central 51 1,308
Plains 35 1,006
Northern 2 1,156
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88 3,470
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TRUST UNIT DATA
Three months ended Six months ended
June 30 June 30
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% %
(millions of units) 2007 2006 change 2007 2006 change
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Weighted average
Basic 239.0 165.8 44 238.0 164.6 45
Diluted 241.5 168.7 43 240.3 167.6 43
Outstanding as at
June 30
Basic 239.2 235.3 2
Basic plus trust
unit rights 253.7 246.0 3
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Letter to our Unitholders
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During the second quarter of 2007, Penn West continued to advance all of its significant initiatives. These included the continuing execution of our conventional asset development and optimization plans, the evaluation of our Peace River Oil Sands project, the advancement of our Pembina CO2 pilot, and continuing engineering, planning and pilot testing to set up commercial CO2 enhanced oil recovery programs on some of the largest legacy light oil pools in Western Canada. We continue to focus our efforts on controlling our lifting costs and capital efficiencies while enhancing our health, safety and environmental stewardship programs.
In April 2007, we closed the acquisition of light oil and natural gas assets and infrastructure that includes important processing infrastructure and all-weather roads in our Peace River Oil Sands project area. In May 2007, we announced a take-over bid for the shares of C1 Energy Ltd. ("C1") for $0.20 per share, or a total acquisition cost of approximately $23 million, which we closed in late July 2007. We also closed the issuance of US$ 475 million of unsecured notes with fixed terms ranging from eight to 15 years. The proceeds from the notes were used to repay a portion of our bank credit facilities. In June 2007, Shirley McClellan was elected as a director of Penn West. Mrs. McClellan will bolster our Board using her experience gained during her distinguished career with the Government of Alberta, which included the offices of Minister of Finance and Deputy Premier.
Cash flow in the second quarter of 2007 was $326 million or $1.37 per unit basic compared to $311 million or $1.31 per unit basic in the first quarter of 2007 and $265 million or $1.59 per unit basic in the second quarter of 2006. For 2007, we expect to generate cash flow between $1.3 billion and $1.4 billion from forecast production of between 129,000 and 132,000 barrels of oil equivalent per day. Subject to this forecast cash flow and capital expenditures, our Board of Directors recently resolved to maintain our distributions at $0.34 per unit per month for the next three months. Production averaged 126,600 barrels of oil equivalent in the second quarter of 2007 compared to 128,447 and 93,242 barrels of oil equivalent in first quarter of 2007 and second quarter of 2006 respectively. The increases in the 2007 production and cash flow over the second quarter of 2006 primarily reflects the Petrofund merger we closed on June 30, 2006 partially offset by the stronger Canadian dollar. The tank farm fire at our Wildboy gas plant reduced our reported natural gas production in the second quarter of 2007 by approximately 20 mmcf per day (approximately 3,300 barrels of oil equivalent per day). We have since restored production at Wildboy to approximately 50 percent of the pre-fire level and expect to have production fully restored by October 2007. We expect that our property insurance will cover the majority of the capital costs to replace the damaged equipment and that our business interruption insurance will cover a significant portion of the lost cash flow.
Operationally, at our Peace River Oil Sands project, we elected to increase our focus on delineating the resources contained in our 300,000 net acres of oil sands leases in the area by scaling back the pace of our development drilling. In addition to the 19 horizontal wells planned to be drilled before year-end, we are also planning a total of 38 stratigraphic test wells, 3-D seismic programs and area mapping over the next six to nine months. To increase our netbacks from the area, we are currently connecting 41 producing wells to our central oil processing battery, thereby eliminating all associated trucking costs. By year-end, we expect to have completed the drilling and facility construction related to a six-well water flood pilot project in our Seal Main area.
On the CO2 enhanced oil recovery side, we are expanding our Pembina CO2 pilot project to include four new horizontal wells and one new vertical well, and plan to commence injecting CO2 by the first quarter of 2008. At South Swan Hills, we expect our eight-well vertical CO2 pilot will be operational by January 2008 and are continuing to de-water our four horizontal wells at our Mannville coalbed methane pilot project.
The proposed tax on income trusts (the "trust tax") received Royal Assent in the House of Commons on June 22. Currently, Penn West will be subject to the new tax under this legislation effective in 2011 and may increase its equity by approximately $10 billion over the period to 2011 without pre-maturely triggering the trust tax. As a result of the tax enactment in the second quarter, Penn West recorded a $326 million non-cash future income tax charge against income, which led to our first reported quarterly loss since 1992. The charge has no impact on our cash flow and hence has no effect on our distributions. Excluding the charge, second quarter 2007 net income would have been $140 million ($0.59 per unit, basic) compared to $96 million ($0.41 per unit, basic) in the first quarter of 2007. Based on our current forecasts, little or no trust or corporate income tax will be paid until approximately 2014. Our efforts to obtain a re-evaluation of the trust tax are continuing in collaboration with other parties.
Over the remainder of 2007, we will work diligently to restore production at Wildboy and advance all of our conventional and non-conventional projects. On behalf of our Board of Directors, I wish to thank Jeffery Errico for his counsel as a Director of Penn West since the merger with Petrofund in June 2006. Mr. Errico did not stand for re-election to our Board due to personal reasons.
On behalf of the Board of Directors,
(signed)
William E. Andrew
President and CEO
Calgary, Alberta
August 1, 2007
MANAGEMENT'S DISCUSSION AND ANALYSIS
For the six months ended June 30, 2007
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This management's discussion and analysis ("MD&A") of financial conditions and results of operations should be read in conjunction with the unaudited interim consolidated financial statements of Penn West Energy Trust ("Penn West", "the Trust", "we" or "our") for the three and six months ended June 30, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006. The date of this MD&A is August 1, 2007.
All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.
Please refer to our disclaimer on forward-looking statements at the end of this MD&A. The calculations of barrels of oil equivalent ("boe") are based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil. This could be misleading if used in isolation as it is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Measures including cash flow, cash flow per unit-basic, cash flow per unit-diluted and netbacks included in this MD&A are not defined in generally accepted accounting principles ("GAAP") and do not have a standardized meaning prescribed by GAAP; accordingly, they may not be comparable to similar measures provided by other issuers. Management utilizes cash flow and netbacks to assess financial performance, to allocate its capital among alternative projects and to assess our capacity to fund distributions and future capital programs. Reconciliations of non-GAAP measures to their nearest measure prescribed by GAAP are provided below.
Calculation of Cash Flow
Three months ended Six months ended
June 30 June 30
($ millions, except --------------------------------------------
per unit amounts) 2007 2006 2007 2006
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Cash flow from operating
activities $ 316.5 $ 218.7 $ 613.3 $ 426.4
Increase in non-cash
working capital 0.9 43.4 5.7 72.0
Asset retirement expenditures 8.8 2.6 18.5 9.5
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Cash flow $ 326.2 $ 264.7 $ 637.5 $ 507.9
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Basic per unit $ 1.37 $ 1.59 $ 2.68 $ 3.08
Diluted per unit $ 1.35 $ 1.56 $ 2.65 $ 3.03
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Quarterly Financial Summary
($ millions, except per unit and production amounts) (unaudited)
Penn West Energy Trust
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June 30 Mar. 31 Dec. 31 Sept. 30 June 30
Three months ended 2007 2007 2006 2006 2006
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Gross revenues(1) $ 608.3 $ 582.4 $ 578.5 $ 636.0 $ 452.5
Cash flow 326.2 311.3 303.3 365.6 264.7
Basic per unit 1.37 1.31 1.23 1.55 1.59
Diluted per unit 1.35 1.30 1.22 1.53 1.56
Net (loss) income (185.2) 96.3 122.9 177.8 220.5
Basic per unit (0.77) 0.41 0.44 0.66 1.34
Diluted per unit (0.77) 0.40 0.44 0.65 1.31
Distributions declared 243.5 242.4 241.5 240.7 167.6
Per unit 1.02 1.02 1.02 1.02 1.02
Production
Liquids(2) (bbls/d) 70,923 71,716 70,819 69,215 48,599
Natural gas (mmcf/d) 334.1 340.4 354.6 359.1 267.9
Total (boe/d) 126,599 128,447 129,915 129,059 93,242
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Penn West Energy Trust
------------------------------
Mar. 31 Dec. 31 Sept. 30
Three months ended 2006 2005 2005
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Gross revenues(1) $ 433.9 $ 554.5 $ 535.0
Cash flow 243.2 332.6 334.9
Basic per unit 1.49 2.03 2.06
Diluted per unit 1.47 2.03 2.04
Net (loss) income 144.4 241.1 209.5
Basic per unit 0.88 1.48 1.29
Diluted per unit 0.87 1.46 1.27
Distributions declared 162.0 151.8 127.3
Per unit 0.99 0.93 0.78
Production
Liquids(2) (bbls/d) 52,226 51,953 51,634
Natural gas (mmcf/d) 266.9 277.5 289.0
Total (boe/d) 96,713 98,205 99,802
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(1) Gross revenues include realized gains and losses on commodity
contracts.
(2) Includes crude oil and natural gas liquids.
Enactment of the Tax on Income Trusts
On June 12, 2007, the legislation implementing the new tax on publicly traded income trusts and limited partnerships (the "SIFT tax"), referred to as "Specified investment flow-through" ("SIFT") entities (Bill C-52) received third reading in the House of Commons and on June 22, 2007, the Bill received Royal Assent. As a result, the tax was considered to be enacted for accounting purposes in June 2007.
SIFTs are certain publicly traded income and royalty trusts and limited partnerships including Penn West. For SIFTs in existence on October 31, 2006, the SIFT tax will be effective in 2011 unless certain rules related to "undue expansion" are not adhered to. Under the guidance provided, we can increase our equity by approximately $10 billion between now and 2011 without prematurely triggering the SIFT tax.
Under the SIFT tax, distributions will not be deductible for income tax purposes by SIFTs in 2011 and thereafter and any trust level taxable income will be taxed at an approximate of the corporate income tax rate currently estimated to be 31.5 percent. The resultant distributions will be considered taxable dividends to unitholders, generally eligible for the dividend tax credit. Distributions representing a return of capital for income tax purposes will continue to be an adjustment to a unitholder's adjusted cost base of trust units.
For accounting purposes, as the SIFT tax was enacted in the second quarter of 2007, Penn West recorded a non-cash charge of $326 million to future income taxes to reflect the current temporary differences between the book and tax basis of assets and liabilities expected to be remaining in the Trust in 2011. The majority of the temporary differences at the Trust level arose on the merger with Petrofund on June 30, 2006.
Our Board of Directors and Management continue to review the impact of this tax on our business strategy. We expect future technical interpretations and details will further clarify the legislation. At the present time, Penn West believes some or all of the following actions will or could result due to the enactment of the SIFT tax:
- If structural or other similar changes are not made, the after-tax
distribution yield in 2011 to taxable Canadian investors will remain
approximately the same, however, the distribution yield in 2011 to
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.)
and foreign investors would fall by an estimated 31.5 percent and
26.5 percent, respectively;
- A portion of Penn West's cash flow could be allocated to the payment
of the SIFT tax, or other forms of tax, and would not be available
for distribution or re-investment;
- Penn West could convert to a corporate structure to facilitate
investing a higher proportion or all of its cash flow in exploration
and development projects. Such a conversion and change to capital
programs could result in a significant reduction to, or elimination
of, distributions and/or dividends;
- Penn West might determine that it is more economic to remain in the
trust structure, at least for a period of time, and shelter its
taxable income using tax pools and pay all or a portion of its
distributions on a return of capital basis, likely at a lower payout
ratio. Further, as the SIFT tax rate exceeds the corporate income tax
rate that would be applicable to Penn West, some corporate tax might
be paid resulting in all or a portion of distributions being paid on
a return of capital basis at a lower payout ratio
The Trust is reviewing all organizational structures and alternatives to minimize the impact of the SIFT tax on our unitholders. While there can be no assurance that the negative effect of the tax can be minimized or eliminated, Penn West and its advisors will continue to work diligently on these issues.
The table below, provided by the Government of Canada in a backgrounder accompanying its October 31, 2006 announcement, shows a simplified comparison of the effects of the changes to investor tax rates in 2011;
Current System Proposed System
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Income Income
portion Large portion Large
of trust corporation of trust corporation
Investor distributions (dividend) distributions (dividend)
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Taxable Canadian
individuals(1) 46% 46% 45.5% 45.5%
Canadian tax-exempt
investors 0% 32% 31.5% 31.5%
Taxable U.S.
investors(2) 15% 42% 41.5% 41.5%
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(1) All rates in the table are as of 2011, and include both entity- and
investor-level tax (as applicable). Rates for "taxable Canadian
individuals" assume that top personal income tax rates apply and that
provincial governments increase their dividend tax credit for
dividends of large corporations.
(2) Canadian taxes only. U.S. tax will also apply in most cases, net of
any foreign tax credits.
RESULTS OF OPERATIONS
Production
Three months ended Six months ended
June 30 June 30
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% %
Daily production 2007 2006 change 2007 2006 change
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Natural gas (mmcf/d) 334.1 267.9 25 337.2 267.4 26
Light oil and NGL
(bbls/d) 49,635 29,974 66 49,372 30,755 61
Conventional heavy
oil (bbls/d) 21,288 18,625 14 21,945 19,648 12
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Total production
(boe/d)(1) 126,599 93,242 36 127,518 94,968 34
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(1) Barrels of oil equivalent (boe) are based on six mcf of natural gas
being equal to one barrel of oil (6:1)
The increase in production was due to the Petrofund merger closing at the end of June 2006, and to our development and optimization programs. Production in the second quarter of 2007 was slightly below the 128,447 boe per day produced in the first quarter of 2007 due to a fire at our 100% owned Wildboy natural gas plant during mid-May reducing production by approximately 3,300 boe per day for the quarter. Partial production was restored at the property in June 2007.
We strive to maintain an approximately balanced portfolio of liquids and natural gas production provided it is economic to do so. We believe a balance by product helps to reduce exposure to price volatility that can affect a single commodity. In the second quarter of 2007, crude oil and NGL production averaged 70,923 barrels per day (56 percent of production) and natural gas production averaged 334.1 mmcf per day (44 percent of production).
We drilled 13 net wells in the second quarter of 2007, mainly in the Central and Plains areas, compared to 28 in the same period of 2006.
Commodity Markets
Natural Gas
Following exceptional volatility through the winter, natural gas price movements have been relatively muted through the spring, with mild weather providing little incentive to move prices in either direction. Lower natural gas storage levels were offset by weaker demand due to the milder weather. Spot natural gas prices at AECO in the second quarter of 2007 decreased by $0.09 per mcf or one percent from the prior quarter to average $7.37 per mcf. Penn West's average natural gas price in the second quarter of 2007 exceeded AECO spot prices due to the use of fixed price, short-term, physical natural gas contracts. Spot natural gas prices were $1.07 per mcf or 18 percent higher than the second quarter of 2006.
Crude Oil
Due to concerns related to crude oil inventory levels resulting from mild winter weather in the first quarter of 2007, crude oil prices were relatively weak early in the first quarter of 2007 but subsequently recovered in the second quarter of 2007. OPEC production cuts combined with strong North American demand resulted in continued high prices. The Edmonton par price for light, sweet crude oil weakened relative to WTI in the quarter as the Canadian dollar strengthened relative to the US dollar. Heavy oil differentials widened relative to Edmonton par, with Bow River differentials averaging $22.31 per barrel in the second quarter of 2007 compared to $18.86 per barrel in the same quarter of 2006.
Average Sales Prices Received
Three months ended Six months ended
June 30 June 30
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% %
2007 2006 change 2007 2006 change
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Natural gas ($/mcf) $ 7.55 $ 6.14 23 $ 7.57 $ 7.12 6
Risk management
($/mcf) 0.01 0.93 (99) 0.04 0.58 (93)
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Natural gas net
($/mcf) 7.56 7.07 7 7.61 7.70 (1)
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Light oil and
liquids ($/bbl) 65.24 71.96 (9) 62.39 66.93 (7)
Risk management
($/bbl) - (2.11) (100) 0.18 (1.04) (117)
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Light oil and
liquids net ($/bbl) 65.24 69.85 (7) 62.57 65.89 (5)
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Conventional heavy
oil ($/bbl) 42.45 52.85 (20) 41.73 41.29 1
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Weighted average
($/boe) 52.63 51.33 3 51.35 50.26 2
Risk management
($/boe) 0.03 2.00 (99) 0.16 1.30 (88)
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Weighted average
net ($/boe) $ 52.66 $ 53.33 (1) $ 51.51 $ 51.56 -
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Netbacks
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Natural gas
Production
(mmcf/day) 334.1 267.9 25 337.2 267.4 26
Operating netback
($/mcf):
Sales price $ 7.55 $ 6.14 23 $ 7.57 $ 7.12 6
Risk
management(2) 0.01 0.93 (99) 0.04 0.58 (93)
Royalties 1.64 1.45 13 1.65 1.63 1
Operating costs 1.10 0.97 13 1.08 0.96 13
Transportation 0.20 0.21 (5) 0.20 0.22 (9)
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Netback $ 4.62 $ 4.44 4 $ 4.68 $ 4.89 (4)
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Light oil and NGL
Production
(bbls/day) 49,635 29,974 66 49,372 30,755 61
Operating netback
($/bbl):
Sales price $ 65.24 $ 71.96 (9) $ 62.39 $ 66.93 (7)
Risk
management(2) - (2.11) (100) 0.18 (1.04) (117)
Royalties 11.29 10.57 7 11.02 10.69 3
Operating costs 15.28 16.10 (5) 15.21 15.75 (3)
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Netback $ 38.67 $ 43.18 (10) $ 36.34 $ 39.45 (8)
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Conventional
heavy oil
Production
(bbls/day) 21,288 18,625 14 21,945 19,648 12
Operating netback
($/bbl):
Sales price $ 42.45 $ 52.85 (20) $ 41.73 $ 41.29 1
Royalties 6.38 9.39 (32) 6.33 7.45 (15)
Operating costs 12.15 11.49 6 12.12 11.00 10
Transportation 0.03 - - 0.05 0.08 (38)
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Netback $ 23.89 $ 31.97 (25) $ 23.23 $ 22.76 2
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Total liquids
Production
(bbls/day) 70,923 48,599 46 71,317 50,403 41
Operating netback
($/bbl):
Sales price $ 58.40 $ 64.64 (10) $ 56.03 $ 56.93 (2)
Risk
management(2) - (1.30) (100) 0.12 (0.63) (119)
Royalties 9.82 10.12 (3) 9.58 9.43 2
Operating costs 14.34 14.33 - 14.26 13.90 3
Transportation 0.01 - - 0.02 0.03 (33)
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Netback $ 34.23 $ 38.89 (12) $ 32.29 $ 32.94 (2)
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Combined totals
Production
(boe/day)(1) 126,599 93,242 36 127,518 94,968 34
Operating netback
($/boe):
Sales price $ 52.63 $ 51.33 3 $ 51.35 $ 50.26 2
Risk
management(2) 0.03 2.00 (99) 0.16 1.30 (88)
Royalties 9.82 9.45 4 9.72 9.59 1
Operating costs 10.94 10.26 7 10.82 10.07 7
Transportation 0.52 0.60 (13) 0.53 0.64 (17)
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Netback $ 31.38 $ 33.02 (5) $ 30.44 $ 31.26 (3)
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(1) Boe or barrels of oil equivalent are based on six mcf of natural gas
being equal to one barrel of oil (6:1).
(2) Realized component of risk management activities related to oil and
natural gas prices.
Production Revenues
Revenues from the sale of oil, NGL and natural gas consisted of the following:
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
($ millions) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Natural gas $ 231.4 $ 172.4 34 $ 465.8 $ 372.7 25
Light oil and NGL 294.7 190.5 55 559.2 366.8 52
Conventional
heavy oil 82.2 89.6 (8) 165.7 146.9 13
-------------------------------------------------------------------------
Gross revenues(1) $ 608.3 $ 452.5 34 $1,190.7 $ 886.4 34
-------------------------------------------------------------------------
(1) Gross revenues include realized gains and losses on commodity
contracts.
Increases (Decreases) in Production Revenues
($ millions)
-------------------------------------------------------------------------
Gross revenues - January 1 - June 30, 2006 $ 886.4
Increase in light oil and NGL production 222.0
Decrease in light oil and NGL prices
(including realized risk management) (29.6)
Increase in conventional heavy oil production 17.2
Increase in conventional heavy oil prices 1.7
Increase in natural gas production 97.3
Decrease in natural gas prices
(including realized risk management) (4.3)
-------------------------------------------------------------------------
Gross revenues - January 1 - June 30, 2007 $1,190.7
-------------------------------------------------------------------------
Royalties
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Royalties
($ millions) $ 113.1 $ 80.1 41 $ 224.4 $ 165.7 35
Average royalty
rate (%) 19 18 6 19 19 -
$/boe $ 9.82 $ 9.45 4 $ 9.72 $ 9.59 1
-------------------------------------------------------------------------
Expenses
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
($ millions) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Operating $ 126.0 $ 87.2 45 $ 249.7 $ 173.1 44
Transportation 6.0 5.0 20 12.1 10.8 12
Financing 24.3 8.4 189 40.5 14.8 174
Unit-based
compensation $ 5.0 $ 2.4 108 $ 9.8 $ 5.4 81
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
($/boe) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Operating $ 10.94 $ 10.26 7 $ 10.82 $ 10.07 7
Transportation 0.52 0.60 (13) 0.53 0.64 (17)
Financing 2.12 1.00 112 1.76 0.87 102
Unit-based
compensation $ 0.44 $ 0.29 52 $ 0.42 $ 0.32 31
-------------------------------------------------------------------------
Operating
With the continued strong draw on skilled labour and services by the large oil sands projects in Northern Alberta, oil and natural gas producers in the Western Canada Sedimentary Basin continued to experience inflationary, albeit moderating, pressure on operating costs in the second quarter of 2007. A higher proportion of liquids production, combined with production interruptions, also contributed to higher per unit operating costs in 2007 than the comparative second quarter 2006 period. The addition of the Petrofund assets, effective July 1, 2006 with higher operating costs, also contributed to the increase.
In 2006, as natural gas prices fell from close to record highs, some significant oil and natural gas companies cut their capital programs related to natural gas helping to reduce demand for oilfield services, particularly drilling and service rigs. The effect of lower activity, combined with internal Penn West initiatives specifically targeted at reducing operating costs, resulted in the operating cost per barrel of oil equivalent in the second quarter of 2007 being approximately equal to the first quarter of 2007 and fourth quarter of 2006.
A realized gain of $2.0 million (2006 - $2.2 million) on our electricity contracts has been included in the operating costs for the first half of the year.
Financing
The 2007 increase in interest expense was due to both an increase in the average outstanding debt balance and increases in short-term interest rates over 2006. The short end of the yield curve has increased due to rate increases by the central bank in Canada. The increased average loan balance was principally due to the $610 million of debt assumed with the Petrofund merger on June 30, 2006 and the $330 million property acquisition that closed in April 2007.
Penn West Petroleum Ltd. ("the Company") closed the placement of US$475 million of notes on May 31, 2007. The interest rates on the notes are fixed at 5.68 to 6.05 percent for fixed terms of eight to 15 years. In addition, the Company has swaps on $100 million of bank debt that fix the interest rate at approximately 4.36 percent until March 2008. The interest rate on the balance of the Company's long-term debt is currently issued to short-term, floating interest rate debt instruments.
Unit-Based Compensation
Unit-based compensation expense related to Penn West's Trust Unit Rights Incentive Plan is based on the fair value of trust unit rights issued, determined using the Binomial Lattice option-pricing model. The unit-based compensation expense was $5.0 million for the three months ended June 30, 2007, of which $1.3 million was charged to operating expense and $3.7 million was charged to general and administrative expense (2006 - $2.4 million, $0.6 million and $1.8 million respectively). Unit-based compensation expense is based on the fair value of rights issued and is amortized over the remaining vesting periods on a straight-line basis.
General and Administrative Expenses
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
($ millions, except % %
per boe amounts) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Gross $ 20.9 $ 13.4 56 $ 41.9 $ 25.5 64
Per boe 1.81 1.58 15 1.81 1.48 22
Net 12.7 7.1 79 26.5 14.1 88
Per boe $ 1.10 $ 0.83 33 $ 1.15 $ 0.82 40
-------------------------------------------------------------------------
Increases in total and per boe general and administrative costs in 2007 were due to higher staff levels following the Petrofund merger and higher compensation costs. The cost of hiring, compensating and retaining employees and consultants, including the recruitment of professional staff dedicated to optimizing and controlling field operating costs, remains high due to strong demand for staff, particularly those with specialized training and experience. More onerous regulatory compliance activities also contributed to the increase.
Depletion, Depreciation and Accretion ("DD&A")
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
($ millions, except % %
per boe amounts) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Depletion of oil
and natural gas
assets(1) $ 212.2 $ 104.1 104 $ 421.2 $ 210.9 100
Accretion of asset
retirement
obligation(2) 6.2 5.8 7 12.1 11.5 5
-------------------------------------------------------------------------
Total DD&A 218.4 109.9 99 433.3 222.4 95
-------------------------------------------------------------------------
DD&A expense
per boe $ 18.95 $ 12.96 46 $ 18.77 $ 12.94 45
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation.
(2) Represents the accretion expense on the asset retirement obligation
during the period.
Higher DD&A expense in 2007 versus 2006 was due to the Petrofund merger in 2006. The merger was accounted for as a purchase with the purchase price allocated to the net assets acquired. The purchase price allocation to oil and natural gas assets, at their estimated fair value, significantly increased our consolidated depletion base per unit and hence our depletion rate.
Taxes
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
($ millions) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Future income
expense
(reduction) $ 299.0 $ (94.8) (415) $ 254.6 $ (104.7) (343)
-------------------------------------------------------------------------
The second quarter of 2007 future income tax expense, compared to the reduction in the first quarter of 2007, reflects a $325.5 million charge due to the enactment of the SIFT tax legislation during the period. Temporary differences at the Trust level, or differences between book and tax basis of assets and liabilities, were previously not recognized as prescribed under Canadian GAAP since the Trust was required to distribute all of its taxable income. Under the new legislation, in 2011 and beyond, as distributions will no longer be tax deductible, the Trust will not be able to make distributions to reduce its taxable income and thus is no longer considered to be exempt from income taxes for accounting purposes. Accordingly, the future income tax liability was increased to reflect the current temporary differences expected to be remaining at the Trust level in 2011 using the SIFT tax rate of 31.5 percent.
Under our current structure, the operating entities make interest and royalty payments to the Trust, which transfers taxable income to the Trust to eliminate income subject to corporate and other income taxes in the operating entities. With the new legislation, such amounts transferred to the Trust could be taxable beginning in 2011 as distributions will no longer be deductible for income tax purposes. At that time, Penn West could claim tax pools in its operating companies, reduce the income transferred to the Trust, and pay all or a portion of its distributions on a return of capital basis. Until 2011, under the terms of its trust indenture, the Trust is required to distribute amounts equal to at least its taxable income. In the event that the Trust has undistributed taxable income in a taxation year (prior to 2011), an additional special taxable distribution, subject to certain withholding taxes, would be required by the terms of its trust indenture.
The estimate of future income taxes is based on the current tax status of the Trust. Future events, which could materially affect future income taxes such as acquisitions and dispositions and modifications to the distribution policy, are not reflected under Canadian GAAP until the events occur and the related legal requirements have been fulfilled. As a result, future changes to the tax legislation could lead to a material change in the recorded amount of future income taxes.
The new legislation is not expected to directly affect our cash flow levels and distribution policies until 2011 at the earliest.
Cash Flow and Net (Loss) Income
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------
% %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Cash flow(1)
($ millions) $ 326.2 $ 264.7 23 $ 637.5 $ 507.9 26
Basic per unit 1.37 1.59 (14) 2.68 3.08 (13)
Diluted per unit 1.35 1.56 (13) 2.65 3.03 (13)
Net (loss) income
($ millions) (185.2) 220.5 (184) (88.9) 364.9 (124)
Basic per unit (0.77) 1.34 (157) (0.37) 2.22 (117)
Diluted per unit $ (0.77) $ 1.31 (159) $ (0.37) $ 2.18 (117)
-------------------------------------------------------------------------
(1) Cash flow is a non-GAAP measure. See "Calculation of Cash Flow".
Cash flow realized in the first six months of 2007 increased from the comparable 2006 period due to higher production volumes resulting from the Petrofund merger and higher conventional heavy oil prices partially offset by higher operating and financing costs.
In the absence of the $325.5 million non-cash charge taken to reflect the enactment of the SIFT tax, net income for the second quarter and first half of 2007 would have been $140.3 million and $236.6 million, respectively. The remainder of the decrease was due to increased depletion and financing charges following the Petrofund merger that closed on June 30, 2006.
Goodwill
The goodwill balance of $652.0 million resulted from the merger with Petrofund in June 2006. The Trust has determined that there was no goodwill impairment as of June 30, 2007.
Capital Expenditures
Three months ended Six months ended
June 30 June 30
--------------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
Property acquisitions
(dispositions), net $ 351.0 $ (3.4) $ 368.1 $ (5.5)
Land acquisition and
retention 1.6 5.1 4.5 18.5
Drilling and completions 44.1 54.1 165.6 151.0
Facilities and well equipping 80.2 47.7 147.6 94.7
Geological and geophysical 4.3 0.9 8.0 2.2
CO2 pilot costs 1.6 0.8 3.1 1.9
Administrative 0.8 0.6 2.6 1.0
-------------------------------------------------------------------------
Capital expenditures 483.6 105.8 699.5 263.8
-------------------------------------------------------------------------
Business combination - 3,361.3 - 3,361.3
-------------------------------------------------------------------------
Total expenditures $ 483.6 $ 3,467.1 $ 699.5 $ 3,625.1
-------------------------------------------------------------------------
We drilled 13 net wells in the second quarter of 2007, resulting in eight net oil wells, three net natural gas wells and one stratigraphic well with a success rate of 92 percent. Our drilling activities were focused in the Central and Plains areas.
CO2 pilot costs represent capital expenditures related to the Pembina CO2 pilot project, including the cost of injectants, for which no reserves have been booked.
On June 30, 2006, we merged with Petrofund. The fair value of the oil and gas properties acquired of $3.3 billion was added to property, plant and equipment and the remaining $0.7 billion of the purchase price was attributed to goodwill. Goodwill was recorded to reflect that we increased our production capacity to levels which made us the largest conventional oil and gas royalty trust in North America, that we increased our exposure to light oil giving us a better future product balance as we increase our production from the Peace River Oil Sands, that we increased our reserve life index and we gained technological access to, and staff with experience in, resource plays including the Weyburn CO2 project and coalbed methane.
On May 31, 2007, we entered into an agreement with C1 Energy Ltd ("C1") to make an offer to its shareholders to acquire all of the issued and outstanding shares of the company for an estimated cash purchase price of $23 million. After the acquisition of approximately 80 percent of C1 by July 23, 2007, we extended the offer to August 3, 2007. Certain assets of C1 are located in the Peace River Arch area of Alberta further strengthening our position near our Peace River Oil Sands project. The acquisition is expected to close in August 2007.
Our farm-out program is ongoing; since 2005, 378 wells have been drilled on Penn West's lands, including re-completions and re-entries, by independent operators who incur drilling, completions and other capital costs on these plays to earn an interest in the lands. In the second quarter of 2007, 16 wells were drilled on our farm-out lands.
In addition to the above capital expenditures, $8.4 million was capitalized in relation to future income taxes on minor acquisitions in the Swan Hills area, to reflect the acquisition of assets with less tax basis than the purchase price, and $17.1 million was capitalized for additions to asset retirement obligations.
Business Risks
Market Risk Management
We are exposed to normal market risks inherent in the oil and natural gas business, including commodity price risk, credit risk, interest rate risk, foreign currency and environmental risk. From time to time, we attempt to minimize exposure to a portion of these risks by using financial instruments and by other means.
Commodity Price Risk
We have substantial exposure to commodity price fluctuations. Crude oil prices are influenced by worldwide factors such as OPEC actions, supply and demand fundamentals, and political events. Oil prices, North American natural gas supply and demand factors including storage levels influence natural gas prices. Pursuant to our policies, we may, from time to time, manage these risks through the use of costless collars or other financial instruments up to a maximum of 50 percent of forecast sales volumes, net of royalties, for a two-year period or up to 75 percent of forecast sales volumes, net of royalties, for a one-year period.
For a current summary of outstanding oil and natural gas hedging contracts, please refer to "Financial Instruments" later in this MD&A or our website at http://www.pennwest.com/.
Foreign Currency Rate Risk
Prices received for sales of crude oil are referenced to, or denominated in, US dollars, and thus realized oil prices are generally impacted by Canadian to United States exchange rates. When we consider it appropriate, we may use financial instruments to fix or collar future exchange rates. At June 30, 2007, we had US dollar denominated debt with a face value of US$475 million outstanding on which the repayment of principal amount in Canadian dollars is not fixed.
Credit Risk
Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. All of our receivables are with customers in the oil and natural gas industry and are subject to normal industry credit risk. In order to limit the risk of non-performance of counterparties to derivative instruments, we contract only with organizations with high credit ratings or by obtaining security in certain circumstances.
Interest Rate Risk
We currently maintain our debt in floating-rate bank facilities, resulting in exposure to fluctuations in short-term interest rates. From time to time, we may increase the certainty of future interest rates using financial instruments to swap floating interest rates for fixed rates or to collar interest rates. In 2006, we entered into interest rate swaps that fix the interest rate for two years at 4.36 percent on $100 million of bank debt. We also closed the placement of notes totaling US$475 million on May 31, 2007 which bear fixed interest rates at an average rate of 5.8 percent for an average term of 10.1 years.
Greenhouse Gas and Air Emissions Legislation
The Alberta Government has introduced legislation that will enable the province to regulate emissions of Greenhouse Gases. The regulations require facilities that emit over 100,000 tonnes of CO2E/yr (total Greenhouse Gases in terms of CO2 equivalent) to reduce their emissions intensity (quantity of gases released per unit of production) by 12 percent starting July 1, 2007 or pay a fee based on emissions in excess of the targeted reductions. Penn West currently does not operate any facilities that are over the current threshold but it does have a working interest in some facilities that do exceed the threshold. We have been in contact with the operators of these facilities to evaluate the impact of the regulations on our working interest.
The Federal Government has also released its regulatory framework to reduce emissions of both Greenhouse Gases and four smog-forming pollutants with targets coming into force in 2010 and 2015, respectively. Clarification surrounding the regulations is expected in the next year with the regulations to be finalized by 2010.
There are multiple compliance mechanisms under both the Alberta and Federal plans including making contributions to technology funds, emissions trading, and offset credits.
Penn West is in the process of fully evaluating the impact of these regulations. There will be a cost associated with complying with these regulations, but we believe that the cost will be minor. We believe that these new regulations may result in increased interest in CO2 capture, transportation and storage technologies and infrastructure and may assist in the development of our CO2 enhanced oil recovery projects in our light oil pools in Alberta. In the meantime, we will continue our current activities to reduce our emissions intensity, improve our energy efficiency and develop CO2 injection and sequestration infrastructure.
Liquidity and Capital Resources
Capitalization
June 30, 2007 December 31, 2006
-------------------------------------------------------------------------
($ millions) % %
-------------------------------------------------------------------------
Trust units issued, at market $ 8,521 81.8 $ 8,435 86.0
Long-term debt 1,823 17.5 1,285 13.1
Working capital deficiency(1) 77 0.7 86 0.9
-------------------------------------------------------------------------
Total enterprise value $ 10,421 100.0 $ 9,806 100.0
-------------------------------------------------------------------------
(1) Current assets minus current liabilities.
During the first six months of 2007, we paid total distributions, including those funded by the distribution reinvestment plan, of $485.2 million compared to distributions of $324.3 million in the same period of 2006. This increase was due to the increase in the distribution rate from $0.31 per unit, per month in March 2006, to the rate of $0.34, and the additional units issued as consideration for Petrofund in 2006.
Long-term debt at June 30, 2007 was $1,823 million compared to $1,285 million at December 31, 2006. Penn West Petroleum Ltd.'s unsecured, extendible, three-year revolving syndicated credit facility has an aggregate borrowing limit of $1.9 billion with stamping fees ranging from 60 - 115 basis points and standby fees ranging from 12.5 - 22.5 basis points depending on our ratio of consolidated bank debt to income before interest, taxes and depreciation and depletion ("EBITDA"). The syndicated facility expires on August 25, 2009.
On April 18, 2007, the Company entered into an additional $250 million unsecured, demand credit facility. This demand credit facility is priced at the same rates as the Company's existing syndicated credit facility and expires on December 31, 2008.
On May 31, 2007, the Company closed an offering of notes issued on a private placement basis in the United States, with an aggregate principal amount of US$475 million. The Company used the proceeds of the notes to repay a portion of its outstanding bank debt under its credit facilities. The notes mature in eight to 15 years and bear interest at rates between 5.68 and 6.05 percent.
On June 30, 2007, the Company was in compliance with the financial covenant pursuant to the notes, which is that consolidated total debt to consolidated total capitalization is not to exceed 55 percent except in the event of a material acquisition where it is not to exceed 60 percent. The ratio at June 30, 2007 was 28 percent.
On June 30, 2007, the Company was in compliance with all of the financial covenants under its syndicated credit facility. The financial covenants under the syndicated credit facility are as follows:
- Consolidated bank debt to EBITDA shall be less than 3:1 except in
certain circumstances and shall not exceed 3.5:1;
- Consolidated total debt to EBITDA shall be less than 4:1; and
- Consolidated bank debt to total trust capitalization shall not exceed
50 percent except in certain circumstances and shall not exceed
55 percent.
The consolidated senior, and total debt, to EBITDA and the consolidated senior debt to capitalization ratios at June 30, 2007 were 1.27 and 28 percent respectively.
Under the terms of its current trust indenture, the Trust is required to make distributions to unitholders in amounts at least equal to its taxable income. Distributions may be monthly or special and in cash or in trust units at the discretion of our Board of Directors. To the extent that additional cash distributions are paid and capital programs are not adjusted, debt levels may increase. In the event that a special distribution in the form of trust units is declared, the terms of the current trust indenture requires that the outstanding units be consolidated immediately subsequent to the distribution. The number of outstanding trust units would remain at the number outstanding immediately prior to the unit distribution, plus those sold to fund the payment of withholding taxes, and an amount equal to the distribution would be allocated to the unitholders as a taxable distribution.
Our philosophy is to retire approximately 10 percent of our opening asset retirement obligation annually, using our cash flow. Due to the extent of our environmental programs, we believe no benefit would arise from the initiation of a reclamation fund. We believe our program is sufficient to meet or exceed existing environmental regulations and best industry practices. In the event of significant changes to the environmental regulations or the cost of environmental activities, a higher portion of cash flow would be required to fund our environmental expenditures.
Standardized Distributable Cash
Prior to recent guidance from accounting and regulatory standard setters on the disclosure of distributable cash, Penn West believed it was inappropriate to provide disclosures regarding distributable cash to its investors and opted to provide statistics including a reconciliation of cash flow from operating activities to distributions declared and distributions declared as a percentage cash flow from operating activities and net income. In the fourth quarter of 2006, Penn West early adopted the draft guidance on the disclosure of distributable cash released in November 2006. The Canadian Institute of Chartered Accountants issued the Interpretive Release "Standardized Distributable Cash in Income Trusts and Other Flow-Through Entities" in July 2007, which is required for the third quarter of 2007. The interpretive release was early adopted by Penn West in this MD&A. In the new guidance, sustainability concepts are discussed and standardized distributable cash is defined as cash flow from operating activities less adjustments for productive capacity maintenance, long-term unfunded contractual obligations and the effect of any foreseeable financing matters, related to debt covenants, which could impair our ability to pay distributions or maintain productive capacity.
Three months ended Six months ended
June 30 June 30
($ millions, except --------------------------------------------
per unit amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
Cash flow from operating
activities $ 316.5 $ 218.7 $ 613.3 $ 426.4
Productive capacity
maintenance(1) (132.6) (109.2) (331.4) (269.3)
-------------------------------------------------------------------------
Standardized
distributable cash 183.9 109.5 281.9 157.1
Proceeds from the issue
of trust units(2) 37.4 31.8 65.9 51.4
Bank borrowings and working
capital changes 22.2 26.3 138.1 121.1
-------------------------------------------------------------------------
Cash distributions declared $ 243.5 $ 167.6 $ 485.9 $ 329.6
Accumulated cash
distributions, beginning 1,375.7 483.5 1,133.3 321.5
-------------------------------------------------------------------------
Accumulated cash
distributions, ending $ 1,619.2 $ 651.1 $ 1,619.2 $ 651.1
-------------------------------------------------------------------------
Standardized distributable
cash per unit, basic 0.77 0.66 1.18 0.95
Standardized distributable
cash per unit, diluted 0.76 0.65 1.15 0.94
Standardized distributable
cash payout ratio(3) 1.32 1.53 1.72 2.10
-------------------------------------------------------------------------
Distributions declared
per unit $ 1.02 $ 1.02 $ 2.04 $ 2.01
Net income in excess of cash
distributions declared N/A 132% N/A 111%
Cash flows from operating
activities in excess of cash
distributions declared 130% 130% 126% 129%
-------------------------------------------------------------------------
(1) Please refer to our discussion of productive capacity maintenance
below.
(2) Consists of proceeds from the Distribution Reinvestment and Optional
Purchase Plan, the Trust Unit Rights Incentive Plan and the Trust
Unit Savings Plan.
(3) Represents cash distributions declared divided by standardized
distributable cash.
We strive to fund both distributions and maintenance capital programs primarily from cash flow. We initially budget our capital programs at approximately 40-50 percent of annual cash flow. We believe that proceeds from the Distribution Re-investment and Optional Purchase Plan should be used to fund capital expenditures of a longer-term nature. Over the medium term, additional borrowings and equity issues may be required from time to time to fund a portion of our distributions or maintain or increase our productive capacity. On a longer-term basis, adjustments to the level of distributions and/or capital expenditures to maintain or increase our productive capacity may be required based on forecast levels of cash flow, capital efficiency and debt levels.
Productive capacity maintenance is the amount of capital funds required in a period for an enterprise to maintain its ability to generate future cash flow from operating activities at a constant level. As commodity prices can be volatile and short-term variations in production levels are often experienced in our industry, we define our productive capacity as production on a barrel of oil equivalent basis. A quantifiable measure for these short-term variations is not objectively determinable or verifiable due to various factors including the inability to distinguish natural production declines from the effect of production additions resulting from capital and optimization programs, and the effect of temporary production interruptions. As a result, the adjustment for productive capacity maintenance in our calculation of standardized distributable cash is our capital expenditures during the period excluding the cost of any asset acquisitions or proceeds of any asset dispositions. We believe that our current capital programs, based on 40-50 percent of forecast annual cash flow and our current view of our assets and opportunities, including particularly our oil sands projects and proposed enhanced oil recovery projects, and our outlook for commodity prices and industry conditions in the medium term, should be sufficient to maintain our productive capacity in the medium term. We set our hurdle rates for evaluating potential development and optimization projects according to these parameters. Due to the risks inherent in the oil and natural gas industry, particularly our exploration and development activities and inherent variations in commodity prices, there can be no assurance that capital programs, whether limited to the excess of cash flow over distributions or not, will be sufficient to maintain or increase our production levels or cash flow from operating activities. Penn West generally incurs a large proportion of its development expenditures in the first quarter of each calendar year to exploit winter-only access properties. As we strive to maintain sufficient credit facilities and appropriate levels of bank debt, this seasonality is not expected to influence our distribution policies.
Our calculation of standardized distributable cash has no adjustment for long-term unfunded contractual obligations. We believe our only significant long-term unfunded contractual obligation at this time is for asset retirement obligations. Cash flow from operating activities, used in our standardized distributable cash calculation, includes a deduction for abandonment expenditures incurred during the period. We believe that our philosophy to retire approximately 10 percent of our opening asset retirement obligation on an annual basis is sufficient to fund our asset retirement obligations over the life of our reserves.
We currently have no financing restrictions caused by our debt covenants. We regularly monitor our current and forecast debt levels to ensure debt covenants are not exceeded.
($ millions, except indicators) To June 30, 2007
-------------------------------------------------------------------------
Cumulative distributable cash from operations(1) $ 1,300.3
Issue of trust units 192.8
Bank borrowing and working capital change 126.1
-------------------------------------------------------------------------
Cumulative cash distributions declared(1) $ 1,619.2
-------------------------------------------------------------------------
Standardized distributable cash payout ratio(2) 1.25
-------------------------------------------------------------------------
(1) Subsequent to the trust conversion on May 31, 2005.
(2) Represents cumulative cash distributions declared divided by
cumulative standardized distributable cash.
Financial Instruments
We currently have WTI crude oil collars on approximately 25,000 barrels per day from July 1 to December 31, 2007 and 17,500 barrels per day from January 2008 to December 2008. The collars on the 25,000 barrels per day to December 2007 have an average floor price of US$56.00 per barrel and an average ceiling price of US$83.80 per barrel. The 2008 WTI crude oil collars have an average floor price of US$64.25 per barrel and an average ceiling price of US$81.06 per barrel. In addition, Penn West has AECO natural gas collars on approximately 52 mmcf per day from July 1 to December 31, 2007 with an average floor price of $7.81 per mcf and an average ceiling price of $10.50 per mcf and approximately nine mmcf per day for the first quarter of 2008 with an average floor price of $8.18 per mcf and an average ceiling price of $12.15 per mcf.
In the second quarter of 2006, we entered into interest rate swaps that fix the interest rate for two years at approximately 4.36 percent on $100 million of floating interest rate debt.
Other financial instruments outstanding at June 30, 2007 are Alberta electricity contracts, which fix 2007 electricity costs on 67 megawatts at $49.55 per megawatt hour and for 2008 on 2 megawatts at $57.00 per megawatt hour.
Mark to market amounts on all financial instruments outstanding on June 30, 2007 are summarized in note 8 to the unaudited interim consolidated financial statements. Please refer to Penn West's website at http://www.pennwest.com/ for details of financial instruments currently outstanding.
Outlook
The outlook for oil prices remains strong however the outlook for natural gas prices has weakened and the Canadian dollar has reached three decade high levels against the US dollar. We are currently forecasting capital expenditures of $850 million to $950 million in 2007, including net property acquisitions. Estimated average 2007 production is currently forecast between 129,000 and 132,000 boe per day after the estimated reduction due to the Wildboy fire. Using a forward strip, 2007 average WTI oil price of US$69.00, an average $6.60 per mcf AECO natural gas price and an average exchange rate of CAD$1.00 equals US$0.92, 2007 cash flow is currently forecast to be between $1.3 billion and $1.4 billion.
Sensitivity Analysis
Estimated sensitivities to selected key assumptions on 2007 financial results before considering hedging impacts are outlined in the table below.
Impact on Impact on
cash flow(1) net income(1)
-------------------------------------------------------------------------
($ millions, except
per unit amounts)
Change of: Change $ millions $/unit $ millions $/unit
-------------------------------------------------------------------------
Price per barrel
of liquids $1.00 21.5 0.09 15.1 0.06
Liquids production 1,000 14.6 0.06 5.4 0.02
bbls/day
Price per mcf of
natural gas $0.10 9.5 0.04 6.7 0.03
Natural gas
production 10 13.5 0.06 1.4 0.01
mmcf/day
Effective interest
rate 1% 14.1 0.06 8.3 0.03
Exchange rate
($US per $CAD) $0.01 21.3 0.09 15.0 0.06
-------------------------------------------------------------------------
(1) The impact on cash flow and net income is computed based on 2007
forecast commodity prices and production volumes. The impact on net
income assumes that the distribution levels are not adjusted for
changes in cash flow thus changing the incremental future income tax
rate.
Contractual Obligations and Commitments
We are committed to certain payments over the next five calendar years as
follows:
($ millions) 2007 2008 2009 2010 2011 Thereafter
-------------------------------------------------------------------------
Transportation $ 8.0 $ 9.7 $ 5.1 $ 3.2 $ 0.1 $ -
Transportation
($US) 1.1 2.3 2.3 2.3 2.3 8.6
Power infrastructure 4.8 3.9 3.9 3.9 3.9 7.6
Drilling rigs 3.5 7.7 2.4 1.2 - -
Purchase
obligations(1) 6.6 13.3 13.3 13.3 13.3 54.3
Office lease $ 5.1 $ 17.9 $ 17.5 $ 15.1 $ 14.3 $ 117.5
-------------------------------------------------------------------------
(1) These amounts represent estimated commitments of $90.0 million for
CO2 purchases and $24.1 million for processing fees related to
interests in the Weyburn Unit.
Our syndicated credit facility expires on August 25, 2009 and our demand credit facility expires on December 31, 2008. If we were not successful in renewing or replacing them, we would be required to repay all amounts then outstanding on the facilities. In addition, we have US$475 million of fixed- term notes expiring between 2015 and 2022. As we maintain our leverage ratios at relatively modest levels, we believe we will be successful in renewing or replacing our credit facilities on acceptable terms.
Equity Instruments
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Trust units issued:
As at June 30, 2007 239,227,937
Issued on exercise of trust unit rights 32,960
Issued to employee savings plan 42,455
Issued pursuant to distribution re-investment plan 347,755
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As at August 1, 2007 239,651,107
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Trust unit rights outstanding:
As at June 30, 2007 14,465,432
Granted 91,120
Exercised (32,960)
Forfeited (239,648)
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As at August 1, 2007 14,283,944
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Disclosure Controls and Procedures
We have established a Disclosure Committee that is responsible for ensuring that our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us is recorded, processed, summarized and reported within the time periods specified under Canadian securities laws. The committee is also responsible to ensure that our internal controls and procedures are designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure. Our Disclosure Committee includes selected members of senior management, including the Chief Executive Officer, the Chief Operating Officer and the Chief Financial Officer.
As at June 30, 2007, an evaluation of the effectiveness of our disclosure controls and procedures, as defined under Multilateral Instrument 52-109, was completed. The evaluation was completed under the supervision of the Disclosure Committee and with the participation of management. As at June 30, 2007, the design and operating effectiveness of our disclosure controls and procedures were assessed by our Chief Executive Officer and Chief Financial Officer to be operating effectively.
Internal Controls over Financial Reporting
We have assembled a team of qualified and experienced staff and consultants who have been working on compliance with the applicable regulations regarding internal control over financial reporting. As we are listed in both Canada and the United States, the recent changes in Canada to remove the requirement for auditor attestation and to extend the timing of CEO/CFO certification of the effective operation of internal control over financial reporting to 2008 will not affect us. We became a registrant under the U.S. Securities Act of 1934 and listed our trust units on the New York Stock Exchange in June 2006. We are not required to certify or obtain auditor attestation of the operating effectiveness of our internal control over financial reporting until we file our 2007 year-end audited financial statements. To date, all significant financial reporting processes have been documented, assessed, and the resulting modifications to our systems of internal control over financial reporting have been substantially completed. Based on this work to date, no changes were made during the quarter ended June 30, 2007 that materially affected, or would be reasonably likely to materially affect, our internal control over financial reporting.
Accounting Changes and Pronouncements
Effective January 1, 2007, the Trust adopted new Canadian accounting standards being "Comprehensive Income", "Financial Instruments - Disclosure and Presentation", "Hedges", "Financial Instruments - Recognition and Measurement", and "Equity". The adoption of these standards has had no material impact on the Trust's net income or cash flows.
Financial Instruments
Financial instruments are required to be measured at fair value on the balance sheet upon initial recognition of the instrument. Measurement in subsequent periods depends on whether the financial instrument has been classified in one of the following categories: held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities as defined under CICA Handbook Section 3855.
Subsequent measurement and changes in fair value will depend on initial classification, as follows: held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income; available-for-sale financial instruments are measured at fair value with changes in fair value recorded in Other Comprehensive Income ("OCI") until the instrument or a portion thereof is derecognized or impaired at which time the amounts would be recorded in net income.
As the Trust previously elected to discontinue hedge accounting, the adoption of these standards did not change the Trust's accounting for financial instruments. Cash and cash equivalents are designated as held-for-trading and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenues are designated as loans and receivables. Accounts payable and accrued liabilities and long-term debt are designated as other liabilities. Risk management assets and liabilities are derivative financial instruments classified as held-for-trading.
Embedded Derivatives
An embedded derivative is a component of a contract that affects the contract terms in relation to another factor, for example rent costs that fluctuate with oil prices. These "hybrid" contracts are considered to consist of a "host" contract plus an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative if certain conditions are met. These include:
- the economic characteristics and risks of the embedded derivative are
not closely related to the economic characteristics and risks of the
host contract,
- if the embedded derivative separated meets the definition of a
derivative,
- the hybrid contract is not measured at fair value or classified as
held for trading.
The Trust currently has no material embedded derivatives.
Comprehensive Income
Comprehensive income is defined as the change in equity from transactions and other events from non-owner sources. It consists of net income and OCI. OCI refers to items recognized in comprehensive income that are excluded from net income calculated in accordance with generally accepted accounting principles. The Trust currently has no items requiring separate disclosure as OCI on a statement of Comprehensive Income.
Two new Canadian accounting standards have been issued, "Financial Instruments-Disclosure" and "Capital Disclosure", which will require additional disclosure in the Trust's financial statements commencing January 1, 2008 about the Trust's financial instruments as well as its capital and how it is managed.
Related-Party Transactions
During the first six months of 2007, Penn West paid $0.8 million (2006 - $2.3 million) of legal fees to a law firm of which a partner is also a director of Penn West.
Off-Balance-Sheet Financing
We have off-balance-sheet financing arrangements consisting of operating leases. The operating lease payments are summarized in the Contractual Obligations and Commitments section.
Forward-Looking Statements
In the interest of providing Penn West's unitholders and potential investors with information regarding Penn West, including management's assessment of Penn West's future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: the impact on our business and unitholders of the SIFT tax and the different actions that we might take in response to the SIFT tax; drilling plans; sufficiency of insurance related to Wildboy costs and losses; timing for production restoration at Wildboy; tie-in of wells; environmental regulation compliance costs and strategy; production estimates; netback estimates; our business strategy, including our strategy in respect of our Peace River Oil Sands project and enhanced oil recovery projects; product balance; the sufficiency of our environmental program; funding sources for distributions and distribution levels; the funding of our asset retirement obligations; our beliefs and outlook for the maintenance of productive capacity; our outlook for oil and natural gas prices; our forecast 2007 net capital expenditures and the allocation and funding thereof; currency exchange rates; our forecast cash flow; our belief that we will be successful in renewing or replacing our credit facilities on acceptable terms when they expire; and the quantity and recoverability of our oil and natural gas reserves and resources.
With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future oil and natural gas prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates; the amount of future cash distributions that we intend to pay; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out development activities; our ability to restore production at Wildboy and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities.
Although Penn West believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause Penn West's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility in market prices for oil and natural gas; the impact of weather conditions on seasonal demand and ability to execute capital programs; risks inherent in oil and gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally; industry conditions, including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; failure to obtain industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand of crude oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of acquisitions, including the merger with Petrofund Energy Trust; changes in tax law; and the other factors described under "Business Risks" in this document and in Penn West's public filings (including our Annual Information Form) available in Canada at http://www.sedar.com/ and in the United States at http://www.sec.gov/. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, Penn West does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.
