Penn West Announces its Financial Results for the Second Quarter Ended June 30, 2014

CALGARY, Sept. 18, 2014 /CNW/ - Penn West Petroleum Ltd. (TSX – PWT; NYSE – PWE) ("Penn West", the "Company", "we", "us" or "our") is pleased to announce its financial results for the second quarter ended June 30, 2014.  The Company previously announced its key operating results for the second quarter on July 29, 2014.  All figures are in Canadian dollars unless otherwise stated.  All comparative figures for the three and six month periods ended June 30, 2013 are as restated.

PRESIDENT'S MESSAGE

Penn West delivered a strong set of results in the quarter and continued to make progress toward our goals of long-term sustainability and overall competitiveness. Importantly, as we noted in a related press release today regarding our restatement, our long term strategy for our operations, development program and growth going forward is unchanged. We remain well on pace to meet our full year production guidance of 101,000 to 106,000 boe per day for 2014.  Our cash and debt balances were not affected by the restatement, nor were our reserve volumes and values, and our bank facility and senior unsecured notes will continue in effect on their existing terms with delivery of our restated historical and second quarter financial statements. In short, our fundamentals remain strong; our proof point will be execution.

In the quarter, increased production reliability and continued strong development results enabled us to deliver average production of 105,702 boe per day before adjustments, over 65 percent of which were liquids, into a strong commodity environment.  The company fully captured the increase in net sales price during the quarter to our netback per boe as a result of solid cost reduction efforts. Second quarter cash costs have declined roughly $80 million (approximately 20 percent) from the second quarter of 2013, with nearly $55 million of these reductions driven by structural cost changes in the enterprise. On an annualized run rate basis, these structural changes translate to projected annual savings of over $220 million.  We expect our cost profile to continue to improve as a result of our ongoing continuous improvement activities.

Development capital was limited to $65 million in the quarter, as expected, due to breakup conditions; however, the Company drilled ten wells in the quarter and completed a total of 12 wells. Our annual base decline rate is approximately 20 percent; among the best in our peer group.  In early July we had eight drilling rigs operating and we can reiterate our plans to drill 210 wells in the year within previous operated development capital estimates. Importantly our 2015 well planning is largely in place and we expect full year 2016 development plans to be well advanced by the end of 2014. This planning allows us to act with greater certainty and improve our ability to control costs and direct activity to our highest value areas. Our drilling inventory across our core focus areas is comprised of several thousand wells, which we believe represents a decade's worth of drilling opportunities.

We continued to streamline our business and improve our processes in the second quarter. The Company has reduced its headcount by almost 50 percent since our high mark in late 2012, with recent changes to support functions such as accounting, land and information technology.  Together with dramatic improvements to date in development planning and execution cycle times, we expect our workflow and cost structure will become increasingly more competitive. As described in our long-term plan, the Company remains focused on increasing the value of every barrel we produce through better capital efficiency, better cost performance and more consistent delivery.

In summary, we are actively re-creating our Company. While we continue to improve on behaviours and decision making from our past, our present operational delivery performance and our belief that we possess an unrivaled future potential in our core areas, gives us great confidence in the direction we are taking Penn West.

OPERATIONAL HIGHLIGHTS

• As planned, development activities were minimal during the second quarter due to spring break-up with $65 million spent. During this period, we further assessed the results of our successful first quarter 2014 drilling program and continued to review opportunities to improve our operational efficiencies. Over the past several months we have made significant strides in cost improvements and reductions in drilling cycle times and in our view have become the top operator in a number of our core plays and we will continue to build on our efforts to-date.
• Average production was 106,706 boe per day for the second quarter of 2014, with our successful drilling program earlier in the year and improvements to our production reliability allowing our production to remain firm in the quarter despite it being a time of relatively low development activity. Our second quarter 2014 average production includes 1,004 boe per day of adjustments resulting primarily from closing amendments on asset divestments and equalizations adjustments completed earlier in the year. Accordingly, second quarter production performance was 105,702 boe per day before adjustments.
• During the second quarter of 2014 we secured operatorship of Pembina Cardium Unit #11 ("PCU #11") in the core of the Pembina field, a key step for the Company as we continue to build the Cardium as our cornerstone asset.

FINANCIAL HIGHLIGHTS

• Funds flow for the second quarter of 2014 was $298 million ($0.61 per share – basic) compared to $269 million ($0.55 per share – basic) in the first quarter of 2014 as restated. The increase is related to slightly higher commodity prices, the reversal of an operating cost accrual in the quarter, offset by lower production volumes and realized risk management losses as a result of stronger crude oil prices.
• Net income for the second quarter of 2014 was $143 million ($0.29 – per share basic) compared to a net loss of $89 million ($0.18 per share – basic) in the first quarter of 2014 as restated. The increase is primarily attributed to the strengthening of the Canadian dollar compared to the US dollar which led to unrealized foreign exchange gains on our senior unsecured notes denominated in US dollars. Also, in the first quarter 2014, non-cash losses were recorded on non-core property dispositions as we continued to focus our asset base as part of phase two of our disposition strategy under our long-term plan.
• During the second quarter, we renewed our unsecured, revolving syndicated bank facility, voluntarily reducing the borrowing capacity from $3.0 billion to $1.7 billion. The new borrowing capacity aligns with the requirements of our long-term plan over the next five years in addition to reducing future financing costs. Following delivery of the restated historical and second quarter financial statements and related MD&A to the lenders under Penn West's revolving syndicated bank facility and the holders of its senior unsecured notes, the defaults under Penn West's bank facility and the senior unsecured notes will be cured. As a result, the bank facility and notes will continue in effect on their existing terms, including borrowing capacity of $1.7 billion, with no changes to pricing or any other terms of the bank facility and no changes to financial covenants going forward.

DISPOSITION UPDATE

Phase two of our acquisition and divestiture strategy, aimed at further focusing Penn West's asset portfolio and improving the financial flexibility of the enterprise, is proceeding as expected. We expect to provide an update with our third quarter results announcement in early November.

OPERATED DEVELOPMENT ACTIVITY

Operations were limited during the second quarter of 2014 due to spring break-up, allowing us to further assess performance from our first quarter drilling program and evaluate additional opportunities to continue reductions in our cost structures and cycle times. In the second quarter, Penn West drilled 10 (10 net) light oil wells with a success rate of 100 percent, eight (8.0 net) wells were drilled in the Viking and one each was drilled in the Cardium (1.0 net) and the Slave Point (1.0 net).

The table below summarizes the second quarter drilling, completions and tie-in activity:

Table 1: Second Quarter 2014 Light Oil Development Summary

PLAY UPDATES

Cardium

In the Cardium we have reduced the average number of days to drill a well from 22 days to eight, which we believe is best amongst our competitors in the play. With limited activity in the quarter, drilling and completion costs remained unchanged and we believe we continue to set the industry benchmark in the play. We spent development capital of $14 million in the second quarter. The drilling program in the second half of 2014 will feature more multi-well pads that will provide cost efficiencies and drive incremental cost savings.

Importantly, during the second quarter of 2014, we secured operatorship of the PCU #11 in the Pembina field which we believe has significant potential for us. This is a substantial field in the Cardium that has not had any meaningful capital investment over the past several years. We are currently in the process of completing a technical evaluation of PCU #11 and expect to have an initial six well development program commencing in 2015.

In July, we commenced our 30 well program in the Willesden Green area with three drilling rigs and added a fourth drilling rig in August. Our development plan for the second half of 2014 will add a fifth rig in October to complete all drilling activity for the year.

In the Pembina area, second half 2014 activities are planned in the Lodgepole and Pembina Cardium Unit #9 ("PCU #9") areas. Drilling activity began on a seven well program in Lodgepole with one rig in July. Once completed, that rig is scheduled to move to PCU #9 to begin a nine well program later in the year.

During our second half 2014 program, water flood activities are scheduled to continue in Willesden Green and Pembina as we continue to assess expansion of our water flood program in 2015. Generally, our waterflood programs throughout the Cardium area are proceeding, consistent with our long-term plan, and are performing in-line with expectations. Over time, we expect that these programs will have the potential to mitigate natural declines and increase the ultimate recovery of light oil resource in our Cardium areas.

Viking

During the second quarter of 2014, we spent development capital of $10 million drilling eight wells in the Viking as we continued to benefit from what we believe is our industry leading operational results in the area. Our second half 2014 program is significant with 84 wells planned and approximately 75 wells scheduled to be on production by the end of the year. In southwestern Saskatchewan, wet weather caused a minor delay in our Viking program where we have two rigs operating to execute our development program in the second half of 2014. 

Leveraging off the positive results of our 16 wells-per-section down-spacing program earlier in the year, we are continuing to test down-spacing programs across the play. As the largest acreage holder in the core of the Viking play, an expanded down spacing program would significantly increase the existing 400-500 drilling locations we have estimated. In our second half program we also plan to reduce our cost per well to below $800,000 from what we believe to already be a best-in-class cost of $840,000.

Slave Point

We continue to test various drilling and completions techniques in the Slave Point Carbonates, as we focus on optimizing production performance, recoveries, cycle-times and per well costs. Throughout the second quarter of 2014, we continued to monitor the results of our drilling program from earlier in the year. We spent development capital of $16 million in the second quarter.

In Otter, production performance on our first long-reach (3,200 meter) lateral wells is in-line with expectations. We are now monitoring these wells for longer-term performance before broader implementation of this design. In the Red Earth area, the two wells we drilled in the first quarter of 2014 continue to perform above our expectations. In Sawn, the results of our first nitrogen fracture wells experienced average 30-day initial production rates that significantly exceeded our type curve. As in Otter, we are now monitoring these wells for longer-term performance.

Our second half 2014 development activities in the Slave Point include a selective seven well drilling program which began in July, five of which are anticipated to be on production by the end of 2014. The goal of this program is to continue with assessment of each of the areas within the Slave Point, testing various drilling and completions techniques. To be competitive internally, per well drilling and completion costs need to be $4.5 million or lower. Currently, average per well drilling and completion costs in our Slave Point program are running in the $5.1 million range. We believe the required 12 percent reduction in costs is achievable and that the Slave Point will be a significant component of our development program in future years as communicated in our long-term plan.

Duvernay

We spudded the 7-16 horizontal well targeting the Duvernay during the first week of July 2014 as planned. Drilling is complete and logs collected over a 1,900 meter lateral section in the well.  Completion activities will commence in early October. We anticipate having the well on production in December of 2014.

PRODUCTION AND OPERATING COSTS

On July 29, 2014 we reported production volumes of 108,130 boe per day in the second quarter, 2014 that included 2,428 boe per day of adjustments resulting primarily from closing amendments on asset divestitures and equalizations adjustments completed earlier in the year. As a result of the internal review of accounting practices conducted by our Audit Committee, it was determined that 1,424 boe per day of those production adjustments should have been recognized in prior quarters, the determination of which is reflected in our restated historical financial statements. Second quarter production volumes now include 1,004 boe per day of adjustments. Accordingly, production of 105,702 boe per day in the second quarter before adjustments is unchanged.

Reported operating cost of $15.20 per boe in the quarter ($17.82 per boe for the six months ended June 30, 2014), was lower than expected as a result of success in our ongoing cost reduction efforts which caused our operating cost accruals to be too high. In the second quarter we reduced our operating cost accruals to more accurately reflect costs, which resulted in a reduction of $26 million to our reported operating costs. This translates into an accrual adjustment of $2.65 per boe in the second quarter of 2014 ($1.30 per boe for the six months ended June 30, 2014).

Operating cost of $19.12 per boe for the first half of 2014, before the effect of the accrual adjustment, is more indicative of our future and ongoing performance. The company remains committed to further reductions in operating costs from these levels.

DRILLING STATISTICS

CAPITAL EXPENDITURES

Exploration and development capital expenditures have declined from the comparative periods in 2013 due to our more focused capital program in our core areas of the Cardium, Viking and Slave Point plays. Cost reductions and improvements in drilling cycle times have also contributed to the decline as we continue to emphasize our strategy of operational excellence. Our 2014 program is also planned to operate on a more continuous approach with a more balanced spending profile during the year.

LAND

COMMON SHARE DATA

Outlook

This outlook section is included to provide shareholders with information about our expectations as at September 18, 2014 for production and capital expenditures in 2014 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 discussion under "Forward-Looking Statements" and are cautioned that numerous factors could potentially impact our capital expenditure levels and production performance for 2014, including our non-core asset disposition program.

There have been no changes to our guidance for our 2014 forecast average production of 101,000 to 106,000 boe per day, originally disclosed in our January 21, 2014 press release "Penn West Provides Fourth Quarter 2013 Operational Update and Announces Additional Non-Core Asset Dispositions for Expected Proceeds of Approximately $175 Million."

Our 2014 Capital Budget has been revised from $900 million to $820 million to reflect the reclassification of $80 million of the budget from capital expenditures to operating expenses in connection with the restatement of certain of our historical financial statements as described in our September 18, 2014 press release "Penn West Provides Results of Internal Review of Accounting Practices, Files Restated Financial Statements and Confirms no Impact on Strategic Direction". There is no impact on planned development capital activities for 2014 as a result of this adjustment to our guidance. All such press releases are available on our website at www.pennwest.com, on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.

Our current forecast for third quarter average production is approximately 100,000 boe per day based on field estimates. Average production in the third quarter, 2014 is expected to be lower than second quarter, 2014 as additions from planned capital activities are weighted to quarter-end; and as expected, the company experiences higher levels of planned turnaround activity in the quarter.

Non-GAAP Measures

This news release includes non-GAAP measures not defined under International Financial Reporting Standards ("IFRS") including funds flow, funds flow per share-basic, funds flow per share-diluted, netback and gross revenues. Non-GAAP measures do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. Funds flow is cash flow from operating activities before changes in non-cash working capital and decommissioning expenditures. Funds flow is used to assess our ability to fund dividends and planned capital programs. See "Calculation of Funds Flow" below. Netback is a per-unit-of-production measure of operating margin used in capital allocation decisions, to economically rank projects and is the per-unit-of-production amount of revenue less royalties, operating costs, transportation and realized risk management gains and losses. Gross revenue is total revenues including realized risk management gains and losses and is used to assess the cash realizations on commodity sales.

Calculation of Funds Flow

Oil and Gas Information Advisory

Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, we believe that utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Forward-Looking Statements

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. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our progress toward streamlining our business model, process improvement and our goals of long-term sustainability and overall competitiveness; our belief that we remain well on pace to meet our full year production guidance for 2014; our drilling and development planning and the timing thereof and the expected benefits to be derived therefrom; the size of our drilling inventory across our core focus areas and the opportunities to be derived therefrom; our expectations with respect to our workflow and cost structure and our focus on increasing the value of every barrel we produce through focus, better capital efficiency, better cost performance and more consistent delivery; our beliefs with respect to our plans, performance and future potential in our core areas; matters pertaining to our long-term plan, including phase 2 of our acquisition and disposition strategy, capital requirements and the expected benefits to be derived from our long-term plan; matters pertaining to our Cardium play, including our performance with respect to drilling times, drilling and completion costs, the characteristics of our second half 2014 Cardium drilling and development program and the benefits to be derived therefrom, our expectations with respect to PCU #11, our drilling plans thereon and our operatorship thereof and the expected results from our water flood program; matters pertaining to our Viking play, including our beliefs with respect to our operational results in the Viking, the characteristics of our second half 2014 Viking drilling and development program and the benefits to be derived therefrom, our down-spacing program and the benefits to be derived therefrom and our expected cost reductions in the Viking play; matters pertaining to our Slave Point play, including our plans with respect to testing various drilling and completion techniques, well performance expectations, type-curves, the characteristics of our second half 2014 Slave Point drilling and development program and the goals thereof and the benefits to be derived therefrom, our beliefs with respect to future well costs and our beliefs with respect to the development potential of the Slave Point play; matters pertaining to our Duvernay play, including expectations with respect to completion activities, production testing and timing; our expectations with respect to and our efforts to further reduce operating costs; matters pertaining to our 2014 capital program generally; and matters pertaining to our expectations with respect to production and capital expenditures, including our average production guidance, our expectations with respect to certain effects of the restatement of certain financial statements, including no impact on development capital activities for 2014, and our expected third quarter average production based on filed estimates.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: the laws and regulations with which we will be required to comply, including laws and regulations relating to securities, accounting, taxation, royalty regimes and environmental protection; future capital expenditure levels; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future crude oil, natural gas liquids and natural gas production levels; drilling results; future exchange rates and interest rates; future debt levels; the amount of future cash dividends that we intend to pay and the level of participation in our dividend reinvestment plan; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out exploration and development activities 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, including our ability to renew or replace our credit facility and our ability to finance the repayment of our senior unsecured notes on maturity; our ability to execute on planned asset acquisition and divestment programs; our ability to add production and reserves through our development and exploitation activities; performance and decline rates of future development wells; the ability of our historical type curves for particular areas to predict future production levels from wells drilled in such areas; timing and costs of bringing future development wells on stream; the expected inventory of future drilling locations; reservoir response to water flood and other enhanced oil recovery methods; producing well and production equipment reliability and decline rates; operating and administrative cost savings; and performance of non-operated properties.

Although we believe 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 forward-looking statements contained herein will not be correct, which may cause our 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: the possibility that we are unable to execute some or all of our ongoing asset disposition program on favourable terms or at all; the possibility that we will not be able to successfully execute our 2014 plans or our long-term plan, respectively, in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to us and our securityholders as a result of the successful execution of such plans do not materialize; the impact of weather conditions on seasonal demand and our ability to execute capital programs; 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 and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; royalties payable in respect of our oil and natural gas production and changes to government royalty frameworks; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); failure to realize the anticipated benefits of dispositions, acquisitions, joint ventures and partnerships; changes in taxation and other laws and regulations that affect us and our securityholders; and the other factors described under "Risk Factors" in our Revised AIF, and described in our public filings 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, we do not undertake any obligation to publicly update any forward-looking statements.  The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

Subsequent event (Note 10)

Commitments and contingencies (Note 12)

Notes to the Consolidated Financial Statements
(All tabular amounts are in CAD millions except numbers of common shares, per share amounts, percentages and various figures in Note 9)

1. Structure of Penn West

Penn West Petroleum Ltd. ("Penn West" or the "Company") is a senior exploration and production company and is governed by the laws of the Province of Alberta, Canada. The Company operates in one segment, to explore for, develop and hold interests in oil and natural gas properties and related production infrastructure in the Western Canada Sedimentary Basin directly and through investments in securities of subsidiaries holding such interests. Penn West's portfolio of assets is managed at an enterprise level, rather than by separate operating segments or business units. The Company assesses its financial performance at the enterprise level and resource allocation decisions are made on a project basis across Penn West's portfolio of assets, without regard to the geographic location of projects. Penn West owns the petroleum and natural gas assets or 100 percent of the equity, directly or indirectly, of the entities that carry on the remainder of the oil and natural gas business of Penn West, except for an unincorporated joint arrangement (the "Peace River Oil Partnership") in which Penn West's wholly owned subsidiaries hold a 55 percent interest.

2. Restatement of Previously Issued Consolidated Financial Statements

Penn West has restated its consolidated balance sheet as of December 31, 2013, and its consolidated statements of income (loss), consolidated statements of cash flows and consolidated statements of changes in shareholders' equity for the three and six month periods ended June 30, 2013. 

During the second quarter of 2014, information drawing into question the appropriateness of certain of the Company's accounting practices came to the attention of senior management of the Company.  This information led to senior management making a recommendation to the Board of Directors (the "Board") of the Company that the Audit Committee of the Board (the "Audit Committee") conduct an independent review of these practices. At the direction of the Audit Committee, an internal review (the "Review") was undertaken. The Audit Committee, comprised solely of independent directors, retained independent Canadian and U.S. legal counsel, and an independent forensic accounting firm, to assist the Audit Committee in conducting the Review. The Review identified accounting practices that, among other things, had the effect of reducing the Company's previously reported operating expenses and increasing the Company's previously reported royalty expense and capital expenditures in 2014, 2013, 2012 and prior periods, which practices were not supportable and required adjustment. 

The Review determined that the following matters required adjustment: 

• certain expenses reclassified as property, plant and equipment from operating expenses without adequate support;
• certain expenses reclassified as royalties from operating expenses without adequate support;
• certain accrual provisions related to capital expenditures recorded on the balance sheets which were no longer required;
• certain property, plant and equipment incorrectly classified as operating expenses and certain operating expenses incorrectly classified as property, plant and equipment; and
• delays in recording certain oil and natural gas sales and associated volumes related primarily to closing adjustments on asset divestments and equalizations adjustments.

The restatement adjustments related to the following items and are described in the paragraphs following the tables below:

• Property, plant and equipment;
• Operating expenses;
• Royalties;
• Accounts payable and accrued liabilities;
• Shareholders' capital;
• Depletion, depreciation and impairment;
• Gain (losses) on dispositions; and
• Deferred income taxes.

The following tables present the impact of the restatement adjustments on the Company's previously reported consolidated financial statements as of December 31, 2013, and for the three month and six month periods ended June 30, 2013. The "As Restated" columns reflect final adjusted balances after the restatement.

Following is a description of the matters corrected in the restatement adjustments.

Inadequately Supported Reclassification of Operating Expenses
and Property, Plant and Equipment

The Review identified that certain operating expenses were reclassified as property, plant and equipment without adequate support and were determined to be incorrectly recorded as property, plant and equipment. These amounts have now been restated and recorded in operating costs. These adjustments resulted in $31 million during the second quarter of 2013 and $66 million for the first six months of 2013 corrected from property, plant and equipment to operating costs.

Throughout all periods under review, the reclassification of expenditures from operating expenses to property, plant and equipment occurred at the corporate level.  Other aspects of the reclassification process changed over time. For certain periods, attempts were made to analyze supporting documentation to determine which items were properly reclassified as property, plant and equipment.  For other periods, and more recently, it appears that little if any analysis was performed to determine which items ought to be capitalized.  In some cases, there appeared to be no contemporaneous support for the decision to reclassify operating expenses as property, plant and equipment.  The increased capitalization of operating expenses decreased reported operating expenses while correspondingly increasing the reported capital assets of the Company. 

Further analysis within property, plant and equipment and operating costs was undertaken to determine if supported amounts had been appropriately classified within these two categories. The review determined that $3 million in the second quarter of 2013 and $10 million in the first six months of 2013 were incorrectly classified as operating costs. These amounts were adjusted and correctly reclassified as property, plant and equipment. In addition, it was determined that $1 million in the second quarter of 2013 and $2 million for the first six months of 2013 were incorrectly classified as property, plant and equipment. These amounts were adjusted and correctly reclassified as operating costs.

As a result of these adjustments, depletion and depreciation expense, impairment charges, gains (losses) on dispositions and deferred income tax expense (recovery) have also been restated in the second quarter and first six months of 2013.

Reclassification of Operating Expenses to Royalties

The Review also identified a practice of incorrectly reclassifying a portion of operating expenses as royalties in the consolidated statements of income (loss). The rationale for this practice was that it reflected that the Company incurs certain expenses producing royalty holders' share of production, and that expenses so incurred are not properly the Company's operating expenses, but rather, more appropriately attributed to the royalty holders' share of the expenses (and thus booked as royalties).  The Review determined that this practice was not appropriate and that the Company had incorrectly classified operating expenses as royalties. The reclassification reduced reported operating expenses.  The practice did not impact the amount of royalties paid to third parties.  These adjustments resulted in $26 million in the second quarter of 2013 and $51 million for the first six months of 2013 reclassified from royalties to operating expenses. As both royalties and operating expenses are included in the consolidated statements of income (loss), there is no effect on net income in the second quarter or first six months of 2013 or on retained earnings in prior periods.     

Capital Expenditure Over Accruals

The Review identified that in recent years, the Company accrued its capital expenditures in excess of the amounts expended in the relevant year.  Unused accruals should have been reversed to zero at year end.  In recent years, unused accruals were not reversed, but were carried over the year end.  The Review identified an accrual related to capital expenditures at December 31, 2012 of $36 million that was not reversed at March 31, 2013 ($12 million) and at June 30, 2013 ($24 million), despite information being available that indicated that the provision was no longer required. These amounts have been corrected in these financial statements.

Shareholders' Equity

Upon commencement of operations as a corporation on January 1, 2011 on its conversion from a trust to a corporation, Penn West's recorded deficit as at December 31, 2010 was eliminated against share capital on January 1, 2011. The difference in the elimination as a result of the above adjustments was a $211 million reduction in shareholders' capital.

Notes 6 and 10 have been restated to reflect amendments arising as a result of the restatement adjustments described above.

3. Statement of compliance and basis of presentation

a) Statement of Compliance

These unaudited condensed interim consolidated financial statements ("interim consolidated financial statements") are prepared in compliance with IAS 34 "Interim Financial Reporting" and accordingly do not contain all of the disclosures included in Penn West's annual audited consolidated financial statements.

The interim consolidated financial statements were prepared using the same accounting policies, critical accounting judgments and key estimates as in the annual consolidated financial statements as at and for the year ended December 31, 2013, except as described in c) below.

All tabular amounts are in millions of Canadian dollars, except numbers of common shares, per share amounts, percentages and other figures as noted. 

The interim consolidated financial statements were approved for issuance by the Board of Directors on September 17, 2014.

b) Basis of Presentation

The interim consolidated financial statements include the accounts of Penn West and its wholly owned subsidiaries and its proportionate interest in partnerships. Results from acquired properties are included in Penn West's reported results subsequent to the closing date and results from properties sold are included until the closing date.

All intercompany balances, transactions, income and expenses are eliminated on consolidation.

c) Changes in accounting policies

During the first quarter of 2014, Penn West adopted the following standards all of which were applied retrospectively.

IAS 32, "Financial Instruments: Presentation", which clarifies the requirements for offsetting financial assets and liabilities. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability. There was no impact to Penn West on adoption of this standard.

IFRIC 21 "Levies" provides guidance on accounting for levies in accordance with the requirements of IAS 37, "Provisions, Contingent Liabilities and Contingent Assets". There was no impact to Penn West on adoption of this standard.

4. Deferred funding assets

Deferred funding amounts are the amounts recoverable from partners of certain Penn West costs incurred under its joint ventures. In the Peace River Oil Partnership, Penn West recovers a portion of its share of certain capital and operating costs and in the Cordova Joint Venture, a portion of its share of certain capital expenditures. Amounts expected to be settled within the next 12 months are classified as current assets.

5. Exploration and evaluation ("E&E") assets

6. Property, plant and equipment

7. Long-term debt

The split between current and non-current long-term debt is as follows: