Exhibit 99.2
MANAGEMENT’S DISCUSSION AND ANALYSIS
This management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the audited consolidated financial statements and accompanying notes of Penn West Energy Trust (“Penn West”, “the Trust”, “We” or “Our”) for the years ended December 31, 2007 and 2006. The date of this MD&A is March 6, 2008.
For additional information, including the Trust’s audited financial statements and Annual Information Form, go to the Trust’s website at www.pennwest.com, in Canada at www.sedar.com or in the United States at www.sec.gov.
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 may not represent a value equivalency at the wellhead.
Measures including funds flow, funds flow per unit-basic, funds 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 funds flow and netbacks to assess financial performance, to allocate its capital among alternative projects and to assess its 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 Funds Flow
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||
(millions, except per unit amounts) |
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
Cash flow from operating activities |
| $ | 311.7 |
| $ | 261.1 |
| $ | 1,241.8 |
| $ | 1,106.3 |
|
Increase in non-cash working capital |
| 20.7 |
| 32.9 |
| 38.2 |
| 43.6 |
| ||||
Asset retirement expenditures |
| 14.8 |
| 9.3 |
| 51.5 |
| 26.9 |
| ||||
Funds flow |
| $ | 347.2 |
| $ | 303.3 |
| $ | 1,331.5 |
| $ | 1,176.8 |
|
Basic per unit |
| $ | 1.44 |
| $ | 1.23 |
| $ | 5.56 |
| $ | 5.86 |
|
Diluted per unit |
| $ | 1.43 |
| $ | 1.22 |
| $ | 5.51 |
| $ | 5.78 |
|
1
Annual Financial Summary
|
| Year ended December 31 |
| |||||||
(millions, except per unit amounts) |
| 2007 |
| 2006 |
| 2005 |
| |||
Gross revenues (1) |
| $ | 2,461.8 |
| $ | 2,100.9 |
| $ | 1,919.0 |
|
Funds flow |
| 1,331.5 |
| 1,176.8 |
| 1,184.6 |
| |||
Basic per unit |
| 5.56 |
| 5.86 |
| 7.28 |
| |||
Diluted per unit |
| 5.51 |
| 5.78 |
| 7.14 |
| |||
Net income |
| 175.5 |
| 665.6 |
| 577.2 |
| |||
Basic per unit |
| 0.73 |
| 3.32 |
| 3.55 |
| |||
Diluted per unit |
| 0.73 |
| 3.27 |
| 3.48 |
| |||
Total expenditures, net |
| 1,140.2 |
| 577.9 |
| 456.7 |
| |||
Long-term debt at period-end |
| 1,943.2 |
| 1,285.0 |
| 542.0 |
| |||
Distributions paid (2) |
| 976.0 |
| 781.8 |
| 270.9 |
| |||
Dividends paid |
| — |
| — |
| 17.5 |
| |||
Total assets |
| $ | 8,433.0 |
| $ | 8,069.7 |
| $ | 3,967.1 |
|
(1) Gross revenues include realized gains and losses on commodity contracts.
(2) Includes distributions paid and reinvested in trust units under the distribution reinvestment plan.
Quarterly Financial Summary
(millions, except per unit and production amounts)
|
| Dec. 31 |
| Sept. 30 |
| June 30 |
| Mar. 31 |
| Dec. 31 |
| Sept. 30 |
| June 30 |
| Mar. 31 |
| ||||||||
Three months ended |
| 2007 |
| 2007 |
| 2007 |
| 2007 |
| 2006 |
| 2006 |
| 2006 |
| 2006 |
| ||||||||
Gross revenues (1) |
| $ | 644.0 |
| $ | 627.1 |
| $ | 608.3 |
| $ | 582.4 |
| $ | 578.5 |
| $ | 636.0 |
| $ | 452.5 |
| $ | 433.9 |
|
Funds flow |
| 347.2 |
| 346.8 |
| 326.2 |
| 311.3 |
| 303.3 |
| 365.6 |
| 264.7 |
| 243.2 |
| ||||||||
Basic per unit |
| 1.44 |
| 1.44 |
| 1.37 |
| 1.31 |
| 1.23 |
| 1.55 |
| 1.59 |
| 1.49 |
| ||||||||
Diluted per unit |
| 1.43 |
| 1.43 |
| 1.35 |
| 1.30 |
| 1.22 |
| 1.53 |
| 1.56 |
| 1.47 |
| ||||||||
Net income (loss) |
| 127.0 |
| 137.4 |
| (185.2 | ) | 96.3 |
| 122.9 |
| 177.8 |
| 220.5 |
| 144.4 |
| ||||||||
Basic per unit |
| 0.53 |
| 0.57 |
| (0.77 | ) | 0.41 |
| 0.44 |
| 0.66 |
| 1.34 |
| 0.88 |
| ||||||||
Diluted per unit |
| 0.52 |
| 0.57 |
| (0.77 | ) | 0.40 |
| 0.44 |
| 0.65 |
| 1.31 |
| 0.87 |
| ||||||||
Distributions declared |
| 247.0 |
| 245.0 |
| 243.5 |
| 242.4 |
| 241.5 |
| 240.7 |
| 167.6 |
| 162.0 |
| ||||||||
Per unit |
| $ | 1.02 |
| $ | 1.02 |
| $ | 1.02 |
| $ | 1.02 |
| $ | 1.02 |
| $ | 1.02 |
| $ | 1.02 |
| $ | 0.99 |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Liquids (bbls/d) (2) |
| 73,332 |
| 72,783 |
| 70,923 |
| 71,716 |
| 70,819 |
| 69,215 |
| 48,599 |
| 52,226 |
| ||||||||
Natural gas (mmcf/d) |
| 328.1 |
| 315.4 |
| 334.1 |
| 340.6 |
| 354.6 |
| 359.1 |
| 267.9 |
| 266.9 |
| ||||||||
Total (boe/d) |
| 128,024 |
| 125,345 |
| 126,599 |
| 128,447 |
| 129,915 |
| 129,059 |
| 93,242 |
| 96,713 |
|
(1) Gross revenues include realized gains and losses on commodity contracts.
(2) Includes crude oil and natural gas liquids.
The major trend changes above are largely due to the acquisition of Petrofund Energy Trust (“Petrofund”) on June 30, 2006 and the enactment of the Specified Investment Flow-Through tax legislation in the second quarter of 2007.
Canetic Acquisition
On January 11, 2008, the close of the acquisition of Canetic Resources Trust (“Canetic”) was successfully completed. Canetic unitholders received 0.515 of a Penn West unit for each Canetic unit on a tax-deferred basis for Canadian and U.S. tax purposes plus a one-time special distribution of $0.09 per unit under the terms of the Combination Agreement.
2
Estimated Total Consideration |
| (millions) |
| |
124.3 million Penn West trust units issued |
| $ | 3,572.5 |
|
Transaction costs |
| 17.0 |
| |
Bank debt |
| 1,467.0 |
| |
Convertible debentures |
| 260.0 |
| |
Working capital deficiency |
| 153.0 |
| |
Total |
| $ | 5,469.5 |
|
Vault Acquisition
On January 10, 2008 the close of the acquisition of Vault Energy Trust (“Vault”) was successfully completed. The acquisition was accomplished through a Plan of Arrangement wherein Vault unitholders received 0.14 of a Penn West trust unit for each Vault unit and all Vault exchangeable shares were exchanged for Penn West trust units based on the exchange ratio for Vault units at the effective date of the Plan of Arrangement. Subsequent to the close of the Vault acquisition, Penn West made its compulsory offer to redeem the Vault convertible debentures for cash at 101 percent of the principle amounts. On March 5, 2008, Penn West retired $23.8 million of the principle amount of the debentures for $24.5 million including the premium and accrued interest.
Estimated Total Consideration |
| (millions) |
| |
5.6 million Penn West trust units issued |
| $ | 157.9 |
|
Transaction costs |
| 5.0 |
| |
Bank debt |
| 88.8 |
| |
Convertible debentures |
| 100.9 |
| |
Working capital deficiency |
| 33.4 |
| |
Total |
| $ | 386.0 |
|
The New Alberta Royalty Framework
On October 25, 2007, the Government of Alberta (the “Government”) released its new royalty framework which is to become effective January 1, 2009. The new framework maintains or continues certain programs that are important to Penn West:
· Conventional production from oil sands leases will maintain oil sands administrative status which benefits our Peace River Oil Sands project due to the reduced royalty rates;
· Enhanced Oil Recovery (“EOR”) and Innovative Energy Technology incentive programs will continue. Penn West has significant inventories of legacy light oil interests amenable to EOR and interests in CO2 EOR producing and other CO2 pilot projects; and
· Otherwise Flared Solution Gas Waiver Program will continue, which supports our long-standing environmental operating and asset optimization objectives.
On conventional production, the Government confirmed that its new royalty framework will be sensitive to well productivity and commodity prices at slightly higher thresholds than the September 18, 2007 proposals of the Alberta Royalty Review Panel. Penn West, as the largest energy trust in North America, has a diversity of play types across the Western Canada Sedimentary Basin. Approximately 60 percent of our production is from Alberta Crown leases and our historical asset strategies have favoured mature assets. We are currently assessing the impact that the new royalty framework will have on our conventional capital allocations for 2008 and beyond. We currently expect that our conventional producing oil and natural gas strategies and business plans will only be minimally affected at current commodity prices and at our current asset mix.
In January 2008, ministers of the Government of Alberta publically stated that a possible re-review of the new Alberta Royalty Framework could occur, with the objective of avoiding “unintended consequences” such as disincentives to drill certain types of wells; however, no details have been formally announced.
3
Enactment of the Tax on Income Trusts
On June 12, 2007, the federal legislation (Bill C-52) implementing the new tax on publicly traded income trusts and limited partnerships (the “SIFT tax”), referred to as “Specified Investment Flow-Through” (“SIFT”) entities received third reading in the House of Commons and on June 22, 2007, the Bill received Royal Assent.
For SIFTs in existence on October 31, 2006 including Penn West, the SIFT tax will be effective in 2011 unless certain rules related to “undue expansion” are not adhered to. Under the guidance provided, with the recent close of Vault and Canetic and along with other transactions, we can increase our equity by approximately $15 billion between now and 2011 without prematurely triggering the SIFT tax.
Under the SIFT tax, distributions from certain types of income will not be deductible for income tax purposes by SIFTs in 2011, and thereafter, and any resultant trust level taxable income will be taxed at approximately the corporate income tax rate. The SIFT rate was initially proposed at 31.5 percent; however, on October 30, 2007, the Government of Canada, in its Mini-Budget (Bill C-28), proposed reductions to the general corporate tax rate, thereby reducing the SIFT rate to 29.5 percent in 2011 and 28.0 percent in 2012 and later. On December 14, 2007 Bill C-28 received Royal Assent, resulting in a reduction to the SIFT tax rate as it becomes effective in 2011, and lowering the rate at which any corporate income taxes will be paid in Penn West’s operating entities. As the Trust currently has a significant tax pool base and expects to increase its tax pool base until 2011, it is expected that the Trust could shelter its taxable income for a period after the effective date of the SIFT tax. Distributions of this nature would not be currently taxable to unitholders as they would represent a return of capital that would continue to be an adjustment to a unitholder’s adjusted cost base of trust units. Distributions from income subject to the SIFT tax will be considered taxable dividends to unitholders and will generally be eligible for the dividend tax credit. The SIFT tax was not intended to adversely affect the after-tax yield of Canadian investors who hold Penn West units in a non-tax deferred account.
For accounting purposes, the SIFT tax charge during the second quarter of 2007 was $325.5 million reflecting the current estimate of the 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 Penn West Trust level resulted from the acquisition of Petrofund on June 30, 2006.
Penn West Petroleum Ltd.’s Board of Directors and management are continuously monitoring the impact of this tax on our business strategies. 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 in the future due to the SIFT tax:
· If structural or other similar changes are not made, the distribution yield net of the SIFT tax in 2011 and beyond to taxable Canadian investors will remain approximately the same; however, the distribution yield to tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) would fall by an estimated 29.5 percent in 2011 and 28.0 percent in 2012 and beyond. For U.S. investors, the distribution yield net of the SIFT and withholding taxes would fall by an estimated 25.1 percent in 2011 and 23.8 percent in 2012 and beyond;
· A portion of Penn West’s funds flow could be required for the payment of the SIFT tax, or other forms of tax, and would not be available for distribution or reinvestment;
· Penn West could convert to a corporate structure with yield in the form of dividends to facilitate investing a higher proportion or all of its funds flow in exploration and development projects. Such a conversion could result in the reduction, or the elimination, of the current distribution program in favour of higher capital investment and/or a dividend payment program; and
· 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, the tax strategy might involve paying some corporate tax resulting in all or a portion of those distributions being paid on a return of capital basis at a lower payout ratio.
4
The Trust continues to review all organizational structures and alternatives to minimize the impact of the SIFT tax on its 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.
On February 26, 2008, the Government of Canada, in its Federal Budget, announced changes to the SIFT tax rules. The provincial component of the SIFT tax will be based on the provincial rates where the SIFT has a permanent establishment rather than using a 13 percent flat rate. As Penn West currently has its permanent establishment in the Province of Alberta, its combined SIFT tax rate applicable in 2012 is expected to fall from 28 percent to 25 percent.
Business Environment
The current business environment reflects high oil prices offset by weak natural gas prices, a strong Canadian dollar relative to the U.S. dollar, volatile capital markets due to turmoil in debt capital markets caused by asset-backed commercial paper and sub-prime mortgage issues and low interest rates by historical standards, offset by significantly higher credit spreads on corporate debt.
Continuing demand for commodities including crude oil from growing economies such as China and India, increasing oil consumption in many of the oil exporting countries and continuing political instability in parts of the world resulted in oil prices remaining strong in 2007. The price of West Texas Intermediate (“WTI”), the primary benchmark for light crude oil prices, averaged US$72.34 per barrel in 2007, up by approximately nine percent from 2006.
Heavy oil differentials widened slightly in 2007, a result of continued refinery upsets throughout the year. The Canadian Bow River differential to WTI widened by eight percent from 2006.
AECO natural gas prices weakened in 2007, decreasing by five percent to $6.60 per mcf from $6.98 per mcf in 2006. Weak natural gas prices reflected record North American storage levels resulting from warmer than average North American temperatures coupled with record liquefied natural gas (“LNG”) imports driven by warmer than average weather in other parts of the world. Recently, the outlook for natural gas prices has begun to improve as global demand for natural gas has continued to outpace supply due to colder weather resulting in lower North American LNG deliveries and leading to more balanced supply/demand fundamentals.
Lower natural gas prices and a strengthening of the Canadian dollar relative to the U.S. dollar continued to partially offset the benefit of stronger oil prices. Oil sales contracts are generally based on WTI prices denominated in U.S. dollars; therefore the strengthening Canadian dollar reduced Canadian dollar-denominated oil prices. The average exchange rate increased from CAD$1.00 equals US$0.8882 in 2006 to CAD$1.00 equals US$0.9300 in 2007 and is currently approximately at parity.
Royalties came under scrutiny by the Alberta government in 2007 leading to the announcement of the new royalty rate framework for the province with an effective date of January 1, 2009. Other provinces have maintained current royalty structures; however, future changes, both positive and/or negative in nature, may occur.
Operating cost initiatives continue to be a focus of Penn West. During 2007, the industry encountered a slow-down in drilling activity primarily due to low natural gas prices and uncertainties resulting from the Alberta royalty review. Penn West experienced only modest increases in operating costs as a result of these factors.
We have an experienced management team and strong technical staff who are committed to exploiting our assets along with realizing operational efficiencies from our economies of scale. Over the past two years, we have completed significant acquisitions including Canetic, Petrofund and Vault, all adding production and reserves throughout the Western Canada Sedimentary Basin and elsewhere. We are now the largest conventional oil and natural gas trust in North America, with a dominant position in Canada’s legacy light oil pools. These conventional opportunities combined with our unconventional resource plays including our Peace River Oil Sands project, coal bed methane, shale gas and enhanced oil recovery opportunities create the diversity and the flexibility that will help us to adjust to changing economic, political and environmental conditions.
5
Penn West strives to generate and preserve unitholder value by:
· Continuing the development of our high-quality assets, with a balance between low-risk, cost efficient resource plays and further development of our unconventional opportunities such as our Peace River Oil Sands project and CO2 enhanced oil recovery projects;
· Maintaining a stable distribution profile through active risk management activities, maintaining and optimizing our production infrastructure, further consolidating our core asset areas and exploiting opportunities availed by our undeveloped land position;
· Pursuing strategic or accretive acquisitions both domestically and internationally to further expand our already significant inventory of assets; and
· Maintaining our strong financial position and balance sheet and operating with financial discipline.
Unitholder Value Measures
|
| Year ended December 31 |
| |||||||
|
| 2007 |
| 2006 |
| 2005 |
| |||
Funds flow per unit |
| $ | 5.56 |
| $ | 5.86 |
| $ | 7.28 |
|
Distributions per unit |
| $ | 4.08 |
| $ | 4.05 |
| $ | 1.97 |
|
Dividends per unit |
| $ | — |
| $ | — |
| $ | 0.07 |
|
Ratio of year-end bank debt to annual funds flow |
| 1.5 |
| 1.1 |
| 0.5 |
|
Penn West maintained a distribution of $0.34 per unit per month throughout 2007 and had continued that level since the rate was increased in February 2006. Increases in the bank debt to funds flow ratio were primarily due to property acquisitions during 2007 that led to increased debt levels.
Performance Indicators
|
| Year ended December 31 |
| |||||||
|
| 2007 |
| 2006 |
| 2005 |
| |||
Return on capital employed (1) |
| 8.9 | % | 12.8 | % | 17.0 | % | |||
Total assets (millions) |
| $ | 8,433 |
| $ | 8,070 |
| $ | 3,967 |
|
Return on equity (2) |
| 3.6 | % | 18.1 | % | 28.3 | % | |||
(1) Net income before financing charges divided by average total liabilities less current assets.
(2) Net income divided by average unitholders’ equity.
During 2007, pre-tax net income was affected by the $201.6 million unrealized loss on risk management activities in 2007. Further, in the second quarter of 2007, the enactment of the SIFT tax led to a $325.5 million non-cash, future income tax charge during the period. During the fourth quarter of 2007, the Government of Canada announced rate reductions that led to a $106.4 million reduction in the period. If neither the SIFT tax nor the tax rate reductions had been enacted in 2007, return on capital employed and return on equity would have been 13.1 percent and 8.1 percent respectively.
Results Of Operations
Production
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||
Daily production |
| 2007 |
| 2006 |
| % change |
| 2007 |
| 2006 |
| % change |
|
Natural gas (mmcf/d) |
| 328.1 |
| 354.6 |
| (7 | ) | 329.4 |
| 312.5 |
| 5 |
|
Light oil and NGL (bbls/d) |
| 51,070 |
| 48,233 |
| 6 |
| 50,175 |
| 39,514 |
| 27 |
|
Conventional heavy oil (bbls/d) |
| 22,262 |
| 22,586 |
| (1 | ) | 22,019 |
| 20,776 |
| 6 |
|
Total production (boe/d) (1) |
| 128,024 |
| 129,915 |
| (1 | ) | 127,098 |
| 112,369 |
| 13 |
|
(1) Barrels of oil equivalent (boe) are based on six mcf of natural gas being equal to one barrel of oil (6:1).
6
Production in the fourth quarter of 2007 exceeded the 125,345 boe per day produced in the third quarter of 2007 due primarily to the resumption of production at our 100 percent owned Wildboy natural gas plant in November 2007. The plant was running at only partial capacity after a fire at the adjoining tank farm in mid-May of 2007. We expect that our business interruption insurance will cover the majority of the lost funds flow, excluding the deductible portion.
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 fourth quarter of 2007, crude oil and NGL production averaged 73,332 barrels per day (57 percent of production) and natural gas production averaged 328.1 mmcf per day (43 percent of production).
We drilled 43 net wells in the fourth quarter of 2007, mainly in the Central and Plains areas, compared to 52 in the same period of 2006.
Commodity Markets
Natural Gas
North American natural gas prices remained weak in the fourth quarter of 2007, particularly compared to oil prices. Natural gas storage levels continued to grow throughout the fall reaching record levels to offset the increased demand due to the onset of winter. Spot natural gas prices at AECO in the fourth quarter increased to $6.00 per mcf or approximately seven percent over the prior quarter. Penn West’s realized price averaged $6.54 per mcf, including gains from commodity contracts.
Crude Oil
WTI oil prices strengthened in the fourth quarter of 2007, with continued concern over supply and inventory levels coupled with ongoing geo-political concerns. The crude oil market has been extremely volatile in recent months as demand appeared to remain impervious to price. As the Canadian dollar strengthened relative to the U.S. dollar, Edmonton par oil prices traded lower relative to WTI prices through the quarter. Both heavy and sour Canadian oil differentials to the Edmonton par light oil price widened over the third quarter of 2007. Bow River differential to Edmonton averaged $29.50 per barrel compared to $24.60 in the previous quarter due primarily to lower seasonal demand and scheduled refinery turnarounds in the quarter. Penn West’s average price for liquids, including realized losses from commodity contracts, was $65.71 per barrel.
Average Sales Prices Received
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||||||
|
| 2007 |
| 2006 |
| % change |
| 2007 |
| 2006 |
| % change |
| ||||
Natural gas (per mcf) |
| $ | 6.34 |
| $ | 6.97 |
| (9 | ) | $ | 6.85 |
| $ | 6.75 |
| 1 |
|
Risk management (per mcf) |
| 0.20 |
| 0.56 |
| (64 | ) | 0.17 |
| 0.72 |
| (76 | ) | ||||
Natural gas net (per mcf) |
| 6.54 |
| 7.53 |
| (13 | ) | 7.02 |
| 7.47 |
| (6 | ) | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Light oil and NGL (per bbl) |
| 76.99 |
| 57.43 |
| 34 |
| 68.75 |
| 65.02 |
| 6 |
| ||||
Risk management (per bbl) |
| (3.87 | ) | 0.01 |
| — |
| (0.97 | ) | (1.00 | ) | (3 | ) | ||||
Light oil and NGL (per bbl) |
| 73.12 |
| 57.44 |
| 27 |
| 67.78 |
| 64.02 |
| 6 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Conventional heavy oil (per bbl) |
| 48.69 |
| 37.57 |
| 30 |
| 45.26 |
| 43.07 |
| 5 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Weighted average (per boe) |
| 55.44 |
| 46.88 |
| 18 |
| 52.73 |
| 49.58 |
| 6 |
| ||||
Risk management (per boe) |
| (1.02 | ) | 1.53 |
| (167 | ) | 0.06 |
| 1.64 |
| (96 | ) | ||||
Weighted average net (per boe) |
| $ | 54.42 |
| $ | 48.41 |
| 12 |
| $ | 52.79 |
| $ | 51.22 |
| 3 |
|
7
Netbacks
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||||||
|
| 2007 |
| 2006 |
| % change |
| 2007 |
| 2006 |
| % change |
| ||||
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Production (mmcf/day) |
| 328.1 |
| 354.6 |
| (7 | ) | 329.4 |
| 312.5 |
| 5 |
| ||||
Operating netback (per mcf): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Sales price |
| $ | 6.34 |
| $ | 6.97 |
| (9 | ) | $ | 6.85 |
| $ | 6.75 |
| 1 |
|
Risk management (gain) (2) |
| (0.20 | ) | (0.56 | ) | (64 | ) | (0.17 | ) | (0.72 | ) | (76 | ) | ||||
Royalties |
| 1.34 |
| 1.63 |
| (18 | ) | 1.48 |
| 1.53 |
| (3 | ) | ||||
Operating costs |
| 1.17 |
| 1.04 |
| 13 |
| 1.12 |
| 0.99 |
| 13 |
| ||||
Transportation |
| 0.21 |
| 0.18 |
| 17 |
| 0.20 |
| 0.21 |
| (5 | ) | ||||
Netback |
| $ | 3.82 |
| $ | 4.68 |
| (18 | ) | $ | 4.22 |
| $ | 4.74 |
| (11 | ) |
Light oil and NGL |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Production (bbls/day) |
| 51,070 |
| 48,233 |
| 6 |
| 50,175 |
| 39,514 |
| 27 |
| ||||
Operating netback (per bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Sales price |
| $ | 76.99 |
| $ | 57.43 |
| 34 |
| $ | 68.75 |
| $ | 65.02 |
| 6 |
|
Risk management loss (gain) (2) |
| 3.87 |
| (0.01 | ) | — |
| 0.97 |
| 1.00 |
| (3 | ) | ||||
Royalties |
| 13.24 |
| 10.55 |
| 26 |
| 11.94 |
| 10.87 |
| 10 |
| ||||
Operating costs |
| 15.55 |
| 15.36 |
| 1 |
| 15.29 |
| 15.80 |
| (3 | ) | ||||
Netback |
| $ | 44.33 |
| $ | 31.53 |
| 41 |
| $ | 40.55 |
| $ | 37.35 |
| 9 |
|
Conventional heavy oil |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Production (bbls/day) |
| 22,262 |
| 22,586 |
| (1 | ) | 22,019 |
| 20,776 |
| 6 |
| ||||
Operating netback (per bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Sales price |
| $ | 48.69 |
| $ | 37.57 |
| 30 |
| $ | 45.26 |
| $ | 43.07 |
| 5 |
|
Royalties |
| 7.18 |
| 6.46 |
| 11 |
| 6.79 |
| 7.47 |
| (9 | ) | ||||
Operating costs |
| 12.32 |
| 11.88 |
| 4 |
| 12.18 |
| 11.22 |
| 9 |
| ||||
Transportation |
| 0.06 |
| 0.07 |
| (14 | ) | 0.07 |
| 0.07 |
| — |
| ||||
Netback |
| $ | 29.13 |
| $ | 19.16 |
| 52 |
| $ | 26.22 |
| $ | 24.31 |
| 8 |
|
Total liquids |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Production (bbls/day) |
| 73,332 |
| 70,819 |
| 4 |
| 72,194 |
| 60,290 |
| 20 |
| ||||
Operating netback (per bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Sales price |
| $ | 68.40 |
| $ | 51.09 |
| 34 |
| $ | 61.59 |
| $ | 57.46 |
| 7 |
|
Risk management loss (gain) (2) |
| 2.69 |
| (0.01 | ) | — |
| 0.67 |
| 0.66 |
| 2 |
| ||||
Royalties |
| 11.40 |
| 9.24 |
| 23 |
| 10.37 |
| 9.69 |
| 7 |
| ||||
Operating costs |
| 14.57 |
| 14.25 |
| 2 |
| 14.34 |
| 14.22 |
| 1 |
| ||||
Transportation |
| 0.02 |
| 0.02 |
| — |
| 0.02 |
| 0.03 |
| (33 | ) | ||||
Netback |
| $ | 39.72 |
| $ | 27.59 |
| 44 |
| $ | 36.19 |
| $ | 32.86 |
| 10 |
|
Combined totals |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Production (boe/day) (1) |
| 128,024 |
| 129,915 |
| (1 | ) | 127,098 |
| 112,369 |
| 13 |
| ||||
Operating netback (per boe): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Sales price |
| $ | 55.44 |
| $ | 46.88 |
| 18 |
| $ | 52.73 |
| $ | 49.58 |
| 6 |
|
Risk management loss (gain) (2) |
| 1.02 |
| (1.53 | ) | (167 | ) | (0.06 | ) | (1.64 | ) | (96 | ) | ||||
Royalties |
| 9.97 |
| 9.48 |
| 5 |
| 9.72 |
| 9.46 |
| 3 |
| ||||
Operating costs |
| 11.35 |
| 10.61 |
| 7 |
| 11.04 |
| 10.39 |
| 6 |
| ||||
Transportation |
| 0.56 |
| 0.51 |
| 10 |
| 0.52 |
| 0.60 |
| (13 | ) | ||||
Netback |
| $ | 32.54 |
| $ | 27.81 |
| 17 |
| $ | 31.51 |
| $ | 30.77 |
| 2 |
|
(1) Barrels of oil equivalent (boe) 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.
8
Production Revenues
Revenues from the sale of oil, NGL and natural gas consisted of the following:
|
| Year ended December 31 |
| |||||||
(millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Natural gas |
| $ | 856.6 |
| $ | 850.9 |
| $ | 918.2 |
|
Light oil and NGL |
| 1,241.4 |
| 923.4 |
| 757.0 |
| |||
Conventional heavy oil |
| 363.8 |
| 326.6 |
| 243.8 |
| |||
Gross revenues (1) |
| $ | 2,461.8 |
| $ | 2,100.9 |
| $ | 1,919.0 |
|
(1) Gross revenues include realized gains and losses on commodity contracts.
Increases (Decreases) in Production Revenues
(millions) |
|
|
| |
Gross revenues – 2006 |
| $ | 2,100.9 |
|
Increase in light oil and NGL production |
| 249.2 |
| |
Increase in light oil and NGL prices (including realized risk management) |
| 68.9 |
| |
Increase in conventional heavy oil production |
| 19.5 |
| |
Increase in conventional heavy oil prices |
| 17.6 |
| |
Increase in natural gas production |
| 46.1 |
| |
Decrease in natural gas prices (including realized risk management) |
| (40.4 | ) | |
Gross revenues – 2007 |
| $ | 2,461.8 |
|
In the fourth quarter of 2007 gross revenues increased by 11 percent to $644.0 million from $578.5 million in 2006. This was primarily due to a 34 percent increase in light oil and NGL sales prices to $76.99 per bbl in 2007 from $57.43 per bbl in 2006 and a 30 percent increase in conventional heavy oil sales price to $48.69 per bbl in 2007 from $37.57 per bbl in 2006.
Royalties
|
| Year ended December 31 |
| |||||||
|
| 2007 |
| 2006 |
| 2005 |
| |||
Royalties (millions) |
| $ | 450.8 |
| $ | 388.0 |
| $ | 369.7 |
|
Average royalty rate (%) |
| 18 | % | 18 | % | 19 | % | |||
Per boe |
| $ | 9.72 |
| $ | 9.46 |
| $ | 10.15 |
|
Expenses
|
| Year ended December 31 |
| |||||||
(millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Operating |
| $ | 512.2 |
| $ | 426.3 |
| $ | 327.4 |
|
Transportation |
| 24.1 |
| 24.5 |
| 22.7 |
| |||
Financing |
| 92.4 |
| 49.3 |
| 23.2 |
| |||
Unit-based compensation |
| $ | 20.5 |
| $ | 11.3 |
| $ | 77.2 |
|
|
| Year ended December 31 |
| |||||||
(per boe) |
| 2007 |
| 2006 |
| 2005 |
| |||
Operating |
| $ | 11.04 |
| $ | 10.39 |
| $ | 8.99 |
|
Transportation |
| 0.52 |
| 0.60 |
| 0.62 |
| |||
Financing |
| 2.00 |
| 1.20 |
| 0.63 |
| |||
Unit-based compensation |
| $ | 0.44 |
| $ | 0.27 |
| $ | 2.12 |
|
9
Operating
Penn West continued all of its initiatives to limit increases to operating costs. Over the past two years, operating cost escalation occurred industry-wide due to strong demand for skilled labour and oilfield services, particularly drilling and oilfield service rigs. Penn West’s modest increases in operating costs per barrel of oil equivalent were generally due to a higher proportion of liquids production in 2007 than in the comparative 2006 periods. Currently, with the low natural gas price and the recent Alberta royalty recommendations, we are experiencing a slow-down in industry activity that is expected to alleviate some of the high demand for oilfield services in the near future. The addition of the Petrofund assets effective July 1, 2006, with higher operating costs than the Penn West assets, also contributed to the increase.
During the fourth quarter of 2007, operating costs increased by six percent to $135.1 million from $127.7 million in the same period of 2006, due to industry-wide cost escalations.
A realized gain of $11.0 million (2006 – $17.3 million) on our electricity contracts was included in operating costs for the year.
Financing
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 terms of 8 to 15 years and average 5.8 percent. During September 2007, the Company entered into foreign exchange contracts to fix the repayment (in Canadian dollars) on US$250 million at an exchange rate of approximately one Canadian dollar at par with one U.S. dollar. 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 and on $100 million of bank debt that fix the interest rate at approximately 4.26 percent until November 2010. The interest rate on the balance of the Company’s long-term debt is currently based on short-term, floating interest rate debt instruments.
In the fourth quarter of 2007, Penn West incurred $27.2 million of financing charges compared to $17.8 million in the same period of 2006 due to increased debt levels.
The 2007 increase in interest expense resulted from both an increase in the average outstanding debt balance and increases in interest rates over 2006. The U.S. notes contain slightly higher fixed interest rates than the Company was subject to under its syndicated credit facility using short-term money market instruments. Penn West believes the long-term nature and the fixed interest rates inherent in the notes are beneficial for a portion of its capital structure. The increased average loan balance was principally due to property acquisitions in 2007.
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 fair value of rights issued is amortized over the remaining vesting periods on a straight-line basis. The unit-based compensation expense was $5.5 million for the three months ended December 31, 2007, of which $1.5 million was charged to operating expense and $4.0 million was charged to general and administrative expense (2006 – $3.1 million, $0.8 million and $2.3 million, respectively). The amount per boe increased in 2007 due to additional options granted in the period.
10
General and Administrative Expenses
|
| Year ended December 31 |
| |||||||
|
| 2007 |
| 2006 |
| 2005 |
| |||
Gross (millions) |
| $ | 83.3 |
| $ | 62.0 |
| $ | 45.0 |
|
Per boe |
| 1.80 |
| 1.51 |
| 1.24 |
| |||
Net (millions) |
| 50.8 |
| 36.0 |
| 23.1 |
| |||
Per boe |
| $ | 1.10 |
| $ | 0.88 |
| $ | 0.64 |
|
The workplace environment continues to be highly competitive in hiring, compensating and retaining employees and consultants. Professional staff, particularly those with experience and strong technical skills, continue to be in high demand, leading to increased compensation costs. Additional regulatory compliance activities have also contributed to increased costs.
Depletion, Depreciation and Accretion (“DD&A”)
|
| Year ended December 31 |
| |||||||
(millions, except per boe amounts) |
| 2007 |
| 2006 |
| 2005 |
| |||
Depletion of oil and natural gas assets |
| $ | 867.4 |
| $ | 635.0 |
| $ | 416.5 |
|
Accretion of asset retirement obligation (1) |
| 29.3 |
| 19.7 |
| 21.1 |
| |||
Total DD&A |
| $ | 896.7 |
| $ | 654.7 |
| $ | 437.6 |
|
DD&A expense per boe |
| $ | 19.33 |
| $ | 15.96 |
| $ | 12.01 |
|
(1) Represents the accretion expense on the asset retirement obligation during the period.
DD&A expense in 2007 was higher than in 2006 due to a full year of production from the Petrofund assets and a higher depletion rate as a result of the Petrofund acquisition, which closed in June 30, 2006. Penn West accounted for the acquisition as a purchase of Petrofund with the purchase price allocated to the fair value of net identifiable assets acquired. The purchase price allocation to oil and natural gas assets at fair value significantly increased our consolidated depletion base per unit. Preliminary estimates for 2008 indicate the 2008 DD&A rate will further increase due to the Vault and Canetic acquisitions.
Taxes
|
| Year ended December 31 |
| |||||||
(millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Current income |
| $ | — |
| $ | — |
| $ | 54.1 |
|
Future income expense (reduction) |
| 75.4 |
| (106.2 | ) | (1.1 | ) | |||
|
| $ | 75.4 |
| $ | (106.2 | ) | $ | 53.0 |
|
Temporary differences at the Trust level, or differences between book and tax basis of the assets and liabilities, were previously not recognized under GAAP as future income taxes because the Trust was required to distribute all of its taxable income under the terms of its Trust Indenture. Under the SIFT 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.
11
During the second quarter of 2007, a $325.5 million charge was recorded due to the enactment of the SIFT tax legislation during the period. 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 then effective SIFT tax rate of 31.5 percent. On October 30, 2007, the Government of Canada proposed rate reductions which were enacted in Bill C-28 on December 14, 2007 lowering the SIFT tax rate to 29.5 percent in 2011 and to 28.0 percent for 2012 and beyond and reducing future corporate income tax rates by an additional 3.5 percent. During the fourth quarter of 2007, a $106.4 million future income tax reduction was recorded to reflect these substantively enacted tax rates.
On February 26, 2008, the Government of Canada, in its Federal Budget, announced changes to the SIFT tax rules. The provincial component of the SIFT tax will be based on the provincial rates where the SIFT has a permanent establishment rather than using a 13 percent flat rate. For Penn West, the SIFT tax rate applicable in 2012 is expected to fall from 28 percent to 25 percent. As the tax rate change has not been substantively enacted, no future income tax rate benefit has been recorded in the financial statements.
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 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 by the Trust for income tax purposes. At that time, Penn West could claim on its tax pools and pay all or a portion of its distributions on a return of capital basis. Such distributions would not be immediately taxable to investors; they would generally reduce the adjusted cost base of units held by investors, however such distributions would potentially be at a lower payout ratio.
The new legislation is not currently expected to directly affect our funds flow levels and distribution policies until 2011 at the earliest.
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.
Tax Pools
|
| As at December 31 |
| |||||||
(millions) |
| 2007 |
| 2006 |
| 2005 |
| |||
Undepreciated capital cost (UCC) |
| $ | 826.2 |
| $ | 788.3 |
| $ | 519.0 |
|
Canadian oil and gas property expense (COGPE) |
| 1,308.6 |
| 1,091.0 |
| 707.6 |
| |||
Canadian development expense (CDE) |
| 413.7 |
| 428.8 |
| 329.8 |
| |||
Non-capital losses |
| 697.4 |
| 106.1 |
| — |
| |||
Total tax pools |
| $ | 3,245.9 |
| $ | 2,414.2 |
| $ | 1,556.4 |
|
The increase in the 2007 tax pools reflects capital spending and income transfers to the Trust throughout the year. The tax pool figures are net of income deferred in operating partnerships.
Foreign Exchange
In 2007, the Trust had U.S.-dollar-denominated debt totalling $475 million compared to nil in 2006. The Trust recorded unrealized foreign exchange gains of $38.2 million in 2007 related to the outstanding U.S. notes. No gains were realized on these contracts in 2007 as no amounts were settled or converted to Canadian dollars during the year.
12
Funds Flow and Net Income
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||||||
|
| 2007 |
| 2006 |
| % change |
| 2007 |
| 2006 |
| % change |
| ||||
Funds flow (1) (millions) |
| $ | 347.2 |
| $ | 303.3 |
| 14 |
| $ | 1,331.5 |
| $ | 1,176.8 |
| 13 |
|
Basic per unit |
| 1.44 |
| 1.23 |
| 17 |
| 5.56 |
| 5.86 |
| (5 | ) | ||||
Diluted per unit |
| 1.43 |
| 1.22 |
| 17 |
| 5.51 |
| 5.78 |
| (5 | ) | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income (millions) |
| 127.0 |
| 122.9 |
| 3 |
| 175.5 |
| 665.6 |
| (74 | ) | ||||
Basic per unit |
| 0.53 |
| 0.44 |
| 20 |
| 0.73 |
| 3.32 |
| (78 | ) | ||||
Diluted per unit |
| $ | 0.52 |
| $ | 0.44 |
| 18 |
| $ | 0.73 |
| $ | 3.27 |
| (78 | ) |
(1) Funds flow is a non-GAAP measure. See “Calculation of Funds Flow”.
Funds flow realized in 2007 increased from the comparable 2006 period due to higher production volumes resulting from the Petrofund acquisition, partially offset by higher operating and financing costs.
In the absence of the $325.5 million non-cash charge taken in the second quarter of 2007 to reflect the enactment of the SIFT tax and the $106.4 million rate recovery received in the fourth quarter of 2007, net income for 2007 would have been $394.6 million.
|
| Year ended December 31 |
| |||||||||||||
|
| 2007 |
| 2006 |
| 2005 |
| |||||||||
|
| $/boe |
| % |
| $/boe |
| % |
| $/boe |
| % |
| |||
Oil and natural gas revenues (1) |
| $ | 53.08 |
| 100.0 |
| $ | 51.22 |
| 100.0 |
| $ | 52.68 |
| 100.0 |
|
Net royalties |
| (9.72 | ) | (18.3 | ) | (9.46 | ) | (18.4 | ) | (10.15 | ) | (19.3 | ) | |||
Operating expenses (2) |
| (11.04 | ) | (20.8 | ) | (10.39 | ) | (20.3 | ) | (8.99 | ) | (17.1 | ) | |||
Transportation |
| (0.52 | ) | (1.0 | ) | (0.60 | ) | (1.2 | ) | (0.62 | ) | (1.1 | ) | |||
Net operating income |
| 31.80 |
| 59.9 |
| 30.77 |
| 60.1 |
| 32.92 |
| 62.5 |
| |||
General and administrative expenses |
| (1.10 | ) | (2.0 | ) | (0.88 | ) | (1.7 | ) | (0.64 | ) | (1.2 | ) | |||
Interest |
| (2.00 | ) | (3.8 | ) | (1.20 | ) | (2.3 | ) | (0.63 | ) | (1.2 | ) | |||
Realized foreign exchange gain |
| — |
| — |
| — |
| — |
| 2.35 |
| 4.4 |
| |||
Current taxes |
| — |
| — |
| — |
| — |
| (1.48 | ) | (2.8 | ) | |||
Funds flow |
| 28.70 |
| 54.1 |
| 28.69 |
| 56.0 |
| 32.52 |
| 61.7 |
| |||
Unrealized foreign exchange gain (loss) |
| 0.82 |
| 1.5 |
| — |
| — |
| (2.48 | ) | (4.7 | ) | |||
Unit-based compensation |
| (0.44 | ) | (0.8 | ) | (0.27 | ) | (0.5 | ) | (2.12 | ) | (4.0 | ) | |||
Risk management activities (3) |
| (4.35 | ) | (8.2 | ) | 1.18 |
| 2.3 |
| (0.09 | ) | (0.2 | ) | |||
Depletion, depreciation and accretion |
| (19.33 | ) | (36.4 | ) | (15.96 | ) | (31.2 | ) | (12.01 | ) | (22.8 | ) | |||
Future income taxes |
| (1.63 | ) | (3.0 | ) | 2.59 |
| 5.1 |
| 0.03 |
| — |
| |||
Net income |
| $ | 3.77 |
| (7.2 | ) | $ | 16.23 |
| 31.7 |
| $ | 15.85 |
| 30.0 |
|
(1) Gross revenues include realized gains and losses on commodity contracts.
(2) Operating expenses include realized gains on electricity swaps.
(3) Risk management activities relate to the unrealized gain and losses on derivative instruments.
13
Goodwill
The goodwill balance of $652.0 million resulted from the acquisition of Petrofund in June 2006. The Trust has determined that there was no goodwill impairment as of December 31, 2007.
Capital Expenditures
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||
(millions) |
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
Property acquisitions (dispositions), net |
| $ | 19.7 |
| $ | 10.9 |
| $ | 421.7 |
| $ | 5.6 |
|
Land acquisition and retention |
| 0.8 |
| 0.8 |
| 30.2 |
| 19.8 |
| ||||
Drilling and completions |
| 96.1 |
| 86.1 |
| 367.2 |
| 317.4 |
| ||||
Facilities and well equipping |
| 73.0 |
| 57.9 |
| 254.1 |
| 224.6 |
| ||||
Geological and geophysical |
| 0.5 |
| 1.0 |
| 10.2 |
| 3.6 |
| ||||
CO2 pilot costs |
| 9.8 |
| 1.1 |
| 19.8 |
| 3.7 |
| ||||
Administrative |
| 10.8 |
| 1.6 |
| 15.8 |
| 3.2 |
| ||||
Capital expenditures |
| 210.7 |
| 159.4 |
| 1,119.0 |
| 577.9 |
| ||||
Business combination |
| — |
| — |
| 21.2 |
| 3,323.3 |
| ||||
Total expenditures |
| $ | 210.7 |
| $ | 159.4 |
| $ | 1,140.2 |
| $ | 3,901.2 |
|
We drilled 43 net wells in the fourth quarter of 2007, resulting in 25 net oil wells, nine net natural gas wells and nine stratigraphic wells with a success rate of 99 percent. Our drilling activities were focused primarily in the Central and Plains areas.
On June 30, 2006, we closed the acquisition of Petrofund. The fair value of the oil and natural 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.
The acquisition of C1 Energy Ltd (“C1”) for a total cost of approximately $21.2 million closed during the third quarter of 2007 and was accounted for as a purchase. Also, during 2007, we completed a number of other minor property acquisitions.
In addition to the above noted capital expenditures, for the year ended December 31, 2007, $5.1 million was capitalized for future income taxes on acquisitions to reflect the acquisitions with a different tax basis than the purchase prices and $96.6 million was capitalized for additions to asset retirement obligations to reflect the additional retirement obligations from both capital programs and net acquisitions.
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.
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.
14
Commodity Price Risk
Commodity price fluctuations are among the Trust’s most significant exposures. 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 weather, storage levels and LNG imports, influence natural gas prices. In accordance with policies approved by our Board of Directors, 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 contracts, please refer to “Financial Instruments” later in this MD&A or our website at www.pennwest.com which includes all current contracts including those assumed in the Canetic and Vault acquisitions which closed in January 2008.
Foreign Currency Rate Risk
Prices received for sales of crude oil are referenced to, or denominated in, U.S. dollars, and thus realized oil prices are 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.
In September 2007, we entered into foreign exchange contracts to fix the foreign exchange rate on the future repayment of US$250 million of U.S.-dollar-denominated private notes at an exchange rate of approximately one Canadian dollar equalling one U.S. dollar. At December 31, 2007, we had U.S.-dollar-denominated debt with a face value of US$225 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 a portion of our debt in floating-rate bank facilities, which results in exposure to fluctuations in short-term interest rates that have for a number of years been lower than longer-term rates. From time to time, we may increase the certainty of our future interest rates by entering fixed interest rate debt instruments or by using financial instruments to swap floating interest rates for fixed rates or to collar interest rates.
In April 2006, we entered into interest rate swaps for two years at 4.36 percent on $100 million of bank debt and in November 2007 we entered into interest rate swaps for three years at 4.26 percent on $100 million of bank debt, both of which fixed the interest rates for the stated period of time. We closed the placement of notes totalling US$475 million on May 31, 2007 that bear fixed interest rates at an average rate of 5.8 percent for an average term of 10.1 years.
15
Liquidity and Capital Resources
Capitalization
|
| Year ended December 31 |
| |||||||||||||
(millions) |
| 2007 |
| 2006 |
| 2005 |
| |||||||||
Trust units issued, at market |
| $ | 6,270 |
| 74.0 |
| $ | 8,435 |
| 86.0 |
| $ | 6,203 |
| 90.5 |
|
Bank loans and notes |
| 1,943 |
| 22.9 |
| 1,285 |
| 13.1 |
| 542 |
| 7.9 |
| |||
Working capital deficiency (1) |
| 266 |
| 3.1 |
| 86 |
| 0.9 |
| 127 |
| 1.6 |
| |||
Total enterprise value |
| $ | 8,479 |
| 100.0 |
| $ | 9,806 |
| 100.0 |
| $ | 6,872 |
| 100.0 |
|
(1) Current assets minus current liabilities.
During 2007, we paid total distributions, including those funded by the distribution reinvestment plan, of $976.0 million, compared to distributions of $781.8 million in 2006. This increase was due to the increase in the distribution rate from $0.31 per unit, per month in February 2006, to the rate since that time of $0.34 per unit, per month, and the 70.7 million additional units issued as consideration for Petrofund in June 2006.
Long-term debt at December 31, 2007 was $1,943.2 million compared to $1,285.0 million at December 31, 2006. In January 2008, our wholly owned subsidiary, Penn West Petroleum Ltd., amended its unsecured, revolving syndicated credit facility to an aggregate borrowing limit of $4.0 billion expiring on January 11, 2011, to enable the cancellation of the credit facilities of Canetic and Vault. The facility is made up of two revolving tranches; tranche one of the facility is $3.25 billion and extendible, and tranche two is $750 million and non-extendible. Stamping fees range from 55 - 110 basis points and standby fees range from 11.0 - 22.5 basis points depending on our ratio of bank debt to income before interest, taxes and depreciation and depletion (“EBITDA”). The syndicated facility expiry date on both tranches is January 11, 2011.
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 8 to 15 years and bear interest at rates between 5.68 and 6.05 percent.
On December 31, 2007, the Company was in compliance with all of the financial covenants under its syndicated credit facility that closed on January 10, 2008. The financial covenants under the syndicated credit facility, which include the unaudited pro forma Canetic, Vault and Titan Exploration Ltd. (“Titan”) historical results, are as follows:
· Consolidated senior 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 senior debt to total trust capitalization shall not exceed 50 percent except in certain circumstances and shall not exceed 55 percent.
At December 31, 2007, the pro forma consolidated senior and total debt to EBITDA ratios were 1.5:1 and 1.6:1 respectively, and the consolidated senior debt to capitalization ratio was 29.5 percent.
On December 31, 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 certain circumstances where it is not to exceed 60 percent.
16
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 require 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. Penn West has never declared such a distribution and, at the current time, it forecasts that such a special distribution will not be required in 2008.
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 will be 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 funds flow would be required to fund our environmental expenditures.
Standardized Distributable Cash
Prior to the recent guidance from accounting and regulatory standard setters on the disclosure of distributable cash, Penn West’s disclosures regarding distributable cash to its investors focused on statistics including a reconciliation of cash flow from operating activities to distributions declared and distributions declared as a percentage of cash flow from operating activities and net income. The Canadian Institute of Chartered Accountants (“CICA”) issued the Interpretive Release “Standardized Distributable Cash in Income Trusts and Other Flow-Through Entities” in July 2007, which provided further guidance. In the 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 an entity’s ability to pay distributions or maintain productive capacity.
|
| Three months ended December 31 |
| Year ended December 31 |
| ||||||||
(millions, except per unit amounts, ratios and percentages) |
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
Cash flow from operating activities |
| $ | 311.7 |
| $ | 261.1 |
| $ | 1,241.8 |
| $ | 1,106.3 |
|
Productive capacity maintenance (1) |
| (191.0 | ) | (148.5 | ) | (697.3 | ) | (572.3 | ) | ||||
Standardized distributable cash |
| 120.7 |
| 112.6 |
| 544.5 |
| 534.0 |
| ||||
Proceeds from the issue of trust units (2) |
| 50.2 |
| 31.3 |
| 163.1 |
| 118.6 |
| ||||
Debt and working capital changes |
| 76.1 |
| 97.6 |
| 270.3 |
| 159.2 |
| ||||
Cash distributions declared |
| $ | 247.0 |
| $ | 241.5 |
| $ | 977.9 |
| $ | 811.8 |
|
Accumulated cash distributions, beginning |
| 1,864.2 |
| 891.8 |
| 1,133.3 |
| 321.5 |
| ||||
Accumulated cash distributions, ending |
| $ | 2,111.2 |
| $ | 1,133.3 |
| $ | 2,111.2 |
| $ | 1,133.3 |
|
|
|
|
|
|
|
|
|
|
| ||||
Standardized distributable cash per unit, basic |
| $ | 0.50 |
| $ | 0.48 |
| $ | 2.27 |
| $ | 2.66 |
|
Standardized distributable cash per unit, diluted |
| $ | 0.50 |
| $ | 0.47 |
| $ | 2.25 |
| $ | 2.62 |
|
Standardized distributable cash payout ratio (3) |
| 2.05 |
| 2.14 |
| 1.80 |
| 1.52 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Distributions declared per unit |
| $ | 1.02 |
| $ | 1.02 |
| $ | 4.08 |
| $ | 4.05 |
|
Net income as a percentage of cash distributions declared |
| 51 | % | 51 | % | 18 | % | 82 | % | ||||
Cash flow from operating activities as a percentage of cash distributions declared |
| 126 | % | 108 | % | 127 | % | 136 | % |
(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.
17
We strive to fund both distributions and maintenance capital programs primarily from funds flow. We initially budget our capital programs at approximately 40-50 percent of annual funds flow. We believe that proceeds from the Distribution Reinvestment 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 funds 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 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 funds flow and our current view of our assets and opportunities, including particularly our oil sands project, and our proposed enhanced oil recovery projects, and our outlook for commodity prices and industry conditions, 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 variations in commodity prices, there can be no assurance that capital programs, whether limited to the excess of funds flow over distributions or not, will be sufficient to maintain or increase our production levels or cash flow from operating activities. Penn West historically incurred a larger 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 debt, this seasonality is not currently 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 each period. We believe that our current environmental programs will be sufficient to fund our asset retirement obligations over the life of our reserves. Distribution policies are set by our Board of Directors based on funds flow. Distributions in excess of net income may include an economic return of capital to unitholders.
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 ratios) |
| To December 31, 2007 |
| |
Cumulative standardized distributable cash from operations (1) |
| $ | 1,562.9 |
|
Issue of trust units |
| 290.0 |
| |
Bank borrowing and working capital change |
| 258.3 |
| |
Cumulative cash distributions declared (1) |
| $ | 2,111.2 |
|
|
|
|
| |
Standardized distributable cash payout ratio (2) |
| 1.35 |
|
(1) Subsequent to the trust conversion on May 31, 2005.
(2) Represents cumulative cash distributions declared divided by cumulative standardized distributable cash.
18
Financial Instruments
During 2007, Penn West had $201.6 million of unrealized losses on risk management activities compared to a $48.6 million gain in 2006. The losses in 2007 were primarily due to record oil prices experienced in the latter part of the year.
As at December 31, 2007 we had WTI crude oil collars on approximately 30,000 barrels per day for 2008 with an average floor price of US$66.17 per barrel and an average ceiling price of US$81.75 per barrel. In addition, Penn West has AECO natural gas collars on approximately 67.5 mmcf per day for 2008 with an average floor price of $6.68 per mcf and an average ceiling price of $7.70 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. Further to this, in the fourth quarter of 2007, we entered into additional interest swaps that fix the interest rate for three years at 4.26 percent on $100 million of floating interest rate debt.
In the third quarter of 2007, we entered into foreign exchange forward contracts to fix the principal repayment on debt amounts totalling US$250 million at an exchange rate of approximately par.
In January 2008, we entered into 10-year U.S. Treasury forward contracts on a notional principal amount of $250 million at an average fixed treasury rate of 3.6778 percent until June 30, 2008.
Other financial instruments outstanding at December 31, 2007 were Alberta electricity contracts, which fix 2008 electricity costs on 32 megawatts at $75.02 per megawatt-hour and in both 2009 and 2010 fix electricity costs on 30 megawatts at $76.23 per megawatt-hour.
Mark to market amounts on all financial instruments outstanding at December 31, 2007 are summarized in note 11 to the audited consolidated financial statements. Canetic and Vault had entered into a number of financial instruments that were assumed upon closing of these deals. Please refer to Penn West’s website at www.pennwest.com for details of all financial instruments currently outstanding.
Outlook
This outlook section is included to provide unitholders with information as to management’s expectations as at March 6, 2008 for production, revenues and net capital expenditures for 2008 and readers are cautioned that the information may not be appropriate for any other purpose. This information constitutes forward-looking information. Readers should note the assumptions, risks and disclaimers under “Forward-Looking Statements”.
The outlook for oil prices remains strong, while the outlook for natural gas prices remains relatively weak and the Canadian dollar remains strong compared to the U.S. dollar. Including the Canetic and Vault acquisitions, Penn West forecasts 2008 production of between 195,000 boe per day and 205,000 boe per day. Based on a forecast WTI oil price of US$80.00 per barrel, a $6.75 per GJ natural gas price at AECO and a CAD/USD exchange rate of par for 2008, funds flow for 2008 is forecast to be between $2.0 billion and $2.1 billion. Based on this level of funds flow and other factors, we estimate 2008 net capital expenditures of approximately $960 million.
19
Sensitivity Analysis
Estimated sensitivities to selected key assumptions on 2008 financial results, including the impact of the Canetic and Vault acquisitions, and before considering hedging impacts, are outlined in the table below.
|
|
|
| Impact on Funds Flow (1) |
| Impact on Net Income (1) |
| |||||
Change of |
| Change |
| $ millions |
| $/unit |
| $ millions |
| $/unit |
| |
Price per barrel of liquids |
| $ | 1.00 |
| 30.3 |
| 0.08 |
| 21.2 |
| 0.06 |
|
Liquids production |
| 1,000 bbls/day |
| 14.7 |
| 0.04 |
| 4.8 |
| 0.01 |
| |
Price per mcf of natural gas |
| $ | 0.10 |
| 17.2 |
| 0.05 |
| 12.0 |
| 0.03 |
|
Natural gas production |
| 10 mmcf/day |
| 14.2 |
| 0.04 |
| 0.8 |
| — |
| |
Effective interest rate |
| 1 | % | 31.4 |
| 0.08 |
| 22.0 |
| 0.06 |
| |
Exchange rate ($US per $CAD) |
| $ | 0.01 |
| 23.9 |
| 0.06 |
| 16.8 |
| 0.04 |
|
(1) The impact on funds flow and net income is computed based on 2008 forecast commodity prices and production volumes. The impact on net income assumes that the distribution levels are not adjusted for changes in funds 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) |
| 2008 |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| Thereafter |
| ||||||
Long-term debt |
| $ | — |
| $ | — |
| $ | 1,485.4 |
| $ | — |
| $ | — |
| $ | 457.8 |
|
Transportation |
| 13.9 |
| 5.8 |
| 2.2 |
| 0.1 |
| — |
| — |
| ||||||
Transportation ($US) |
| 2.3 |
| 2.3 |
| 2.3 |
| 2.3 |
| 2.3 |
| 6.4 |
| ||||||
Power infrastructure |
| 6.2 |
| 4.2 |
| 4.2 |
| 4.2 |
| 4.2 |
| 7.6 |
| ||||||
Drilling rigs |
| 7.7 |
| 2.4 |
| 1.2 |
| — |
| — |
| — |
| ||||||
Purchase obligations (1) |
| 13.3 |
| 13.3 |
| 13.3 |
| 13.3 |
| 13.2 |
| 41.1 |
| ||||||
Office lease |
| $ | 19.4 |
| $ | 19.6 |
| $ | 17.3 |
| $ | 16.5 |
| $ | 16.2 |
| $ | 104.3 |
|
(1) These amounts represent estimated commitments of $84.4 million for CO2 purchases and $23.1 million for processing fees related to interests in the Weyburn Unit.
The $4.0 billion syndicated credit facility expires on January 11, 2011. If we were not successful in renewing or replacing the facility, we could be required to repay all amounts then outstanding on the facility or enter term bank loans. As we strive to maintain our leverage ratios at relatively modest levels, we believe we will be successful in renewing or replacing our credit facility on acceptable terms.
20
Equity Instruments
Trust units issued: |
|
|
|
As at December 31, 2007 |
| 242,663,164 |
|
Issued on exercise of trust unit rights |
| 330,370 |
|
Issued to employee savings plan |
| 217,988 |
|
Issued pursuant to distribution reinvestment plan |
| 1,116,862 |
|
Issued on Canetic acquisition |
| 124,348,739 |
|
Issued on Vault acquisition |
| 5,550,923 |
|
As at March 6, 2008 |
| 374,228,046 |
|
|
|
|
|
Trust unit rights outstanding: |
|
|
|
As at December 31, 2007 |
| 14,486,084 |
|
Granted |
| 11,296,752 |
|
Exercised |
| (330,370 | ) |
Forfeited |
| (162,244 | ) |
As at March 6, 2008 |
| 25,290,222 |
|
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
Penn West maintains disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by Penn West in its annual filings, interim filings (as these terms are defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) and other reports filed or submitted by it under provincial and territorial securities legislation is recorded, processed, summarized and reported within the required time periods. Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by the annual filings, being December 31, 2007, have concluded that, as of such date, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by Penn West in reports that it files or submits is (i) recorded, processed, summarized and reported within the time periods as required, and (ii) accumulated and made known to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as indicated in the preceding paragraph, the Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures are effective at that reasonable assurance level, although the Chief Executive Officer and Chief Financial Officer do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
21
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the design and effectiveness of our internal control over financial reporting as of the end of the fiscal year covered by this report based on the framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework. Based on this evaluation, management concluded that as of December 31, 2007, Penn West did maintain effective internal control over financial reporting. There have been no changes in Penn West’s internal control over financial reporting during both 2007 and the most recent interim period that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2007 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report.
Accounting Changes and Pronouncements
Effective January 1, 2007, the Trust adopted new Canadian accounting standards issued by the CICA, these 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 funds flows.
Financial Instruments
Financial instruments are 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; and 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 elected to discontinue hedge accounting in 2005, 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.
22
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; and
· 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 GAAP. The Trust currently has no items requiring separate disclosure as OCI on a Statement of Comprehensive Income.
Future Accounting Pronouncements
Three new Canadian accounting standards have been issued: “Financial Instruments – Disclosure”, “Capital Disclosure” and “Goodwill and Intangible Assets”. These will require additional disclosure in the Trust’s financial statements commencing January 1, 2008 related to the Trust’s financial instruments as well as the management of capital. The goodwill and intangible assets section is effective January 1, 2009.
Related-Party Transactions
During 2007, Penn West paid $1.3 million (2006 – $4.1 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.
Critical Accounting Estimates
Our significant accounting policies are detailed in note 2 to the audited consolidated financial statements. In the determination of financial results, we must make certain significant accounting estimates as follows:
Full Cost Accounting
We use the full cost method of accounting for oil and natural gas properties. All costs of exploring for and developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved reserves with forecast commodity pricing.
23
Our reserves were evaluated by GLJ Petroleum Consultants Ltd., an independent engineering firm. In 2007 and 2006, our reserves were determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves is, by its nature, based on complex extrapolations and models as well as other significant engineering, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion and are a key component of value in the ceiling test. To the extent that the ceiling amount, based in part on our reserves, is less than the carrying amount of property, plant and equipment, a write-down against income must be made. We determined there was no ceiling test write-down required at December 31, 2007.
Asset Retirement Obligations
The discounted, expected future cost of statutory, contractual or legal obligations to retire long-lived assets is recorded as an asset retirement liability with a corresponding increase to the carrying amount of the related asset. The recorded liability increases over time to its future liability amount through accretion charges to earnings, included in DD&A. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to our asset retirement obligation. Actual asset retirement expenditures are charged to the liability to the extent of the then-recorded liability. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset. Note 6 to the audited consolidated financial statements details the impact of these accounting recommendations.
Financial Instruments
Financial instruments included in the balance sheets consist of accounts and taxes receivable, the fair value of the derivative financial instruments, current liabilities and the bank loan. The fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments, the mark to market values recorded for the financial instruments and the market rate of interest applied to the bank loan.
All of our accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. We may, from time to time, use various types of financial instruments to reduce our exposure to fluctuating oil and natural gas prices, electricity costs, exchange rates and interest rates. The use of these financial instruments exposes us to credit risks associated with the possible non-performance of counterparties to the derivative contracts. We limit this risk by transacting only with financial institutions with high credit ratings and by obtaining security in certain circumstances.
Our revenues from the sale of crude oil, natural gas liquids and natural gas are directly impacted by changes to the underlying commodity prices. To ensure that funds flows are sufficient to fund planned capital programs and distributions, costless collars or other financial instruments may be utilized. Collars ensure that commodity prices realized will fall into a contracted range for a contracted sales volume. Forward power contracts fix a portion of future electricity costs at levels determined to be economic by management.
Goodwill
Goodwill must be recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance is not amortized; however, it must be assessed for impairment at least annually. Impairment is initially determined based on the fair value of the reporting entity compared to its book value. Any impairment must be charged to income or loss in the period the impairment occurs. We determined there was no goodwill impairment as at December 31, 2007.
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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, distribution policies and unitholders of the SIFT tax and the different actions that we might take in response to the SIFT tax; the impact on our reserves and business of the new Alberta royalty framework drilling plans; sufficiency of insurance related to Wildboy costs and losses; 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 our coal bed methane, shale gas and enhanced oil recovery projects; product balance; the sufficiency of our environmental program; funding sources for distributions, distribution levels and whether a special distribution will be made in 2007; 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 2008 net capital expenditures and the allocation and funding thereof; the section on “Outlook” which sets forth management’s expectations as to production, revenues and net capital expenditures for 2008; the sensitivity of our assumptions regarding 2008 funds flow and net income to changes in certain operational and financial metrics; currency exchange rates; our forecast funds flow; the nature and effectiveness of our risk management strategies; our belief that we will be successful in renewing or replacing our credit facilities on acceptable terms when they expire; the quantity and recoverability of our oil and natural gas reserves and resources, including the quantity of discovered heavy oil resources in place at the Peace River Oil Sands Project; and the ability of Penn West to economically develop its contingent resources at its Peace River Oil Sands Project and convert these resources into reserves.
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 capital expenditure levels; 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; the ability of insurance to offset the financial impact of the fire-related outage at the Wildboy natural gas plant; 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. In addition, the “Outlook” section is based on specific assumptions as to commodity prices and exchange rates, planned capital expenditures and our success in maintaining production and adding new production through our exploitation activities.
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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 natural 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 acquisition of Petrofund Energy Trust, the acquisition of C1 Energy Ltd. and Vault Energy Trust and the acquisition of Canetic Resources Trust; changes in tax law; changes in the Alberta royalty framework; uncertainty of obtaining required approvals for acquisitions and mergers; 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 www.sedar.com and in the United States at 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.
Additional Information
Additional information relating to Penn West including Penn West’s Annual Information Form is available on SEDAR at www.sedar.com.
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