Penn West Announces Its Financial and Operational Results for the Second Quarter Ended June 30, 2016

CALGARY, Aug. 4, 2016 /CNW/ - PENN WEST PETROLEUM LTD. (TSX – PWT; NYSE – PWE) ("Penn West", the "Company", "we", "us" or "our") is pleased to announce its financial and operational results for the second quarter ended June 30, 2016. All figures are in Canadian dollars unless otherwise stated. 






Three months ended June 30

Six months ended June 30


2016

2015

% change

2016

2015

% change

Financial (millions, except per share amounts)









Gross revenues (1,2)

$

209

$

360

(42)

$

440

$

700

(37)

Funds flow (2)


5


47

(89)


94


159

(41)


Basic per share (2)


0.01


0.09

(89)


0.19


0.32

(41)


Diluted per share (2)


0.01


0.09

(89)


0.19


0.32

(41)

Funds flow from operations (2)


55


85

(35)


102


162

(37)


Basic per share (2)


0.11


0.17

(35)


0.20


0.32

(38)


Diluted per share (2)


0.11


0.17

(35)


0.20


0.32

(38)

Net loss


(132)


(28)

>100


(232)


(276)

(16)


Basic per share


(0.26)


(0.06)

>100


(0.46)


(0.55)

(16)


Diluted per share


(0.26)


(0.06)

>100


(0.46)


(0.55)

(16)

Capital expenditures (3)

1


64

(98)


19


255

(93)

Net Debt (4)

$

566

$

2,205

(74)

$

566

$

2,205

(74)























Operations











Daily production












Light oil and NGL (bbls/d)


30,421


51,275

(41)


35,497


51,859

(32)


Heavy oil (bbls/d)


11,427


11,947

(4)


11,934


12,418

(4)


Natural gas (mmcf/d)


130


168

(23)


137


172

(20)

Total production (boe/d) (5)


63,568


91,164

(30)


70,289


93,024

(24)

Average sales price












Light oil and NGL (per bbl)

$

49.66

$

58.05

(14)

$

40.99

 

$

52.05

(21)


Heavy oil (per bbl)


25.18


46.44

(46)


19.75


38.06

(48)


Natural gas (per mcf)

$

1.42

$

2.78

(49)

$

1.70

 

$

2.93

(42)

Netback per boe (5)












Sales price

$

31.20

$

43.84

(29)

$

27.38

 

$

39.53

(31)


Risk management gain (loss)


4.27


(0.49)

>100


5.08


1.51

>100


Net sales price


35.47


43.35

(18)


32.46


41.04

(21)


Royalties


(0.63)


(4.72)

(87)


(0.87)


(4.51)

(81)


Operating expenses (6)


(12.70)


(18.15)

(30)


(12.87)


(18.38)

(30)


Transportation


(1.89)


(1.40)

35


(1.75)


(1.37)

28


Netback (2)

$

20.25

$

19.08

6

$

16.97

 

$

16.78

1



(1)

Includes realized gains and losses on commodity contracts and excludes gains and losses on foreign exchange hedges.

(2)

The terms "gross revenues", "funds flow", "funds flow from operations" and their applicable per share amounts, and "netback" are non-GAAP measures. Please refer to the "Calculation of Funds Flow and Funds Flow from Operations" in the attached Management Discussion and Analysis and "Non-GAAP Measures" sections below.

(3)

Capital expenditures include costs related to Property, Plant and Equipment and Exploration and Evaluation. Includes the effect of capital carried by partners.

(4)

Net debt includes long-term debt and includes the effects of working capital and all cash held or cash offered for prepayment to lenders.

(5)

Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".

(6)

Includes the effect of carried operating expenses from its partner under the Peace River Oil Partnership of $3 million or $0.52 per boe (2015 - $3 million or $0.36 per boe) for the three months ended and $7 million or $0.55 per boe (2015 - $6 million or $0.36 per boe) for the six months ended.

 

President's Message

Penn West recorded a notable second quarter and demonstrated the very strong investment case I believe the company presents. We delivered solid results in our operations and executed a key de-levering event that removes the long-standing debt overhang from the company. We are well on our way to completing the repositioning of our Company as a very focused, very profitable, liquids growth story in western Canada.

Amidst the market uncertainty, our teams stayed focused on the core business to deliver exceptional operational results. Second quarter production of 63,568 boe per day exceeded consensus estimates through a combination of the continued strong performance from Cardium wells drilled last winter and an improvement in the reliability of our base production. Additionally, our ongoing focus on reducing our cost structure allowed us to economically produce volumes that had been previously earmarked to be shut-in.

Second quarter operating expenses of $12.70 per boe, net of carry, came in meaningfully below expectations as a result of operating efficiencies in our well programs leading to a decrease in operating costs and additional overall cost savings, experienced both internally and at a macro level, which resulted in actual results below our initial estimates. Additionally, in the first half of 2016, we deferred several discretionary expenses, primarily related to turnarounds and workover activities, which we believe will result in a modest increase in operating costs in the second half of the year.

In the second quarter, the Company executed a number of asset dispositions, including the sale of its core Slave Point and Saskatchewan properties that dramatically de-levered the balance sheet and realized meaningful value for our shareholders. These dispositions, combined with signed agreements for an incremental $75 million in sales proceeds subsequent to the quarter, reduced our pro-forma Net Debt to approximately $491 million from $2.1 billion at year-end 2015. As a result, we have confirmed our compliance with all of our financial covenants and removed the going concern note previously included in our first quarter financial statements. Importantly, our markedly improved capital structure positions us competitively with our peers in terms of all significant debt metrics.

We will continue to streamline and high-grade the remainder of our portfolio this year in the final steps of our transformation into a leading Alberta oil producer. In the second half of this year, we expect to dispose of non-core assets with associated production of approximately 20,000 boe per day and generate between $100 million and $200 million in proceeds. We remain confident in our ability to sell these assets, as is evidenced by incremental signed agreements subsequent to the quarter.

We are excited to demonstrate the asset quality and strong economics of our core Cardium, Alberta Viking, and Peace River areas. We will take full advantage of our improved financial flexibility now afforded to us and are getting back to work on our future. As a result, we are increasing our capital expenditure program by approximately $40 million, fully paid for by full year funds flow from operations, to restart development in the Cardium and Alberta Viking. We plan to drill 5 wells in the Cardium, 11 wells in the Alberta Viking, and 19 gross wells in the Peace River area. We expect our second-half drilling program to add approximately 3,000 boe per day to our 2016 exit production and set us up for continued growth into next year.

Our teams have conducted a review of our preliminary 2017 plans and anticipate spending up to $150 million in total capital, including decommissioning expenditures, next year. The Cardium will remain the foundation of our development program supported by incremental growth in the Alberta Viking and meaningful cash generation at Peace River.  Next year's program will deliver core production growth of at least 10% from the fourth quarter of 2016 to the fourth quarter of 2017 and will be fully paid for by funds flow from operations.

We can already see the promise of a focused portfolio with our high quality, long life positions in the Cardium, Alberta Viking and Peace River areas. Our second-half 2016 program sets the stage for a long term vision of a top quartile Company with consistent production growth of at least 10% annually, fully funded by funds flow from operations, operating costs of $10 to $12 per boe, and low leverage metrics.

Financial and Operational Highlights

  • As at June 30, 2016, we were in compliance with all of our financial covenants under our lending agreements. Senior Debt to EBITDA was 3.9 times, relative to a 5.0 times limit. Our Net Debt was $566 million, a decrease from $2.1 billion at December 31, 2015. In 2016, we closed several asset dispositions for total proceeds of approximately $1.3 billion, which led to a significant improvement in our balance sheet and a reduction in long-term debt. This disposition activity resulted in compliance with all financial covenants at June 30 and as we expect to remain compliant as we move forward, we have removed the going concern note included in our first quarter 2016 financial statements.

  • On June 30, 2016, we had excess cash totaling $374 million from disposition proceeds that we can offer to our lenders at our discretion. We anticipate applying this cash to reduce our outstanding debt balance during the second half of the year. Assuming these proceeds were offered to lenders as a pro rata pre-payment, pro-forma Senior Debt to EBITDA at June 30, 2016 would have been 2.3 times.

  • Production in the second quarter averaged 63,568 boe per day, ahead of our expectations, primarily due to continued strong production results from our last winter drilling program. Additionally, fewer wells were shut-in than previously anticipated, which also contributed to our production results coming in ahead of expectations. Production in our core areas was approximately 24,000 boe per day in the second quarter.

  • Operating costs per boe, net of carry, were $12.70 during the second quarter as we successfully progressed on a number of strategies to reduce operating costs, with a specific focus on reducing repair & maintenance and workover activities. Additionally, we continued to benefit from cost reductions across the industry and efficiencies within our organization resulting in actual costs coming in below our estimates. In the first half of 2016, we deferred several discretionary expenses, primarily turnarounds and workover activities, into the second half of the year, which contributed to our operating costs coming in ahead of expectations thus far in 2016.

  • During the second quarter of 2016, we closed several asset dispositions for total proceeds of approximately $1.3 billion. These dispositions included our interests in Slave Point, all of our Saskatchewan properties, and several non-core Alberta assets. We plan to sell the remainder of our non-core assets, with associated production of approximately 20,000 boe per day, by the end of the year.

  • Subsequent to the end of the second quarter, we have entered into agreements to sell certain non-core assets as we continue to progress through our disposition initiatives. Estimated proceeds from these dispositions total approximately $75 million with associated average production of approximately 6,000 boe per day. These dispositions would reduce our pro-forma Net Debt to $491 million.

  • In the second half of this year, we plan to resume our development activities in our core areas. We are increasing our full year 2016 capital budget by approximately $40 million to $90 million, plus $15 million allocated for decommissioning expenditures. We expect the accelerated second half development program will increase our 2016 exit production by approximately 3,000 boe per day.

  • We expect full year 2016 production to average 55,000 – 57,000 boe per day in total, prior to the effect of additional dispositions, and 22,000 – 24,000 boe per day in our core areas. Full year operating costs are expected to average between $13.50 and $14.50 per boe and full year G&A costs are expected to average between $2.50 and $2.90 per boe.

Select Metrics in Core Areas

The table below outlines select metrics in our core areas for the six months ended June 30, 2016 and excludes the impact of hedging:



Area

Select Metrics – Six Months Ended June 30, 2016

Production

Liquids Weighting

Operating Cost

Netback

Cardium

18,500 boe/d

68%

$8.50/boe

$24.00/boe

Alberta Viking

1,000 boe/d

40%

$10.50/boe

$5.50/boe

Peace River(1)

5,000 boe/d

98%

$1.00/boe

$13.50/boe

Total Core

24,500 boe/d

73%

$7.00/boe

$21.00/boe


(1)

Net of carried operating costs

 

Operated Development Activity

During the second quarter, Penn West performed a comprehensive review of its core assets, particularly the growth potential of the Cardium and Alberta Viking. The analysis reaffirmed that Penn West's assets are able to deliver strong economic returns in the current commodity price environment and supports further development of its core plays in the Cardium and Alberta Viking, which remain profitable on a full cycle basis.

The table below provides a summary of our operational activity during the second quarter:




Number of Wells


Drilled

Completed

On production


Gross

Net

Gross

Net

Gross

Net

Cardium

0.0

0.0

0.0

0.0

0.0

0.0

Alberta Viking

0.0

0.0

0.0

0.0

0.0

0.0

Peace River

2.0

1.1

2.0

1.1

2.0

1.1

Total Core

2.0

1.1

2.0

1.1

2.0

1.1

 

The additional financial flexibility provided through the meaningful asset dispositions in the quarter has allowed the Company to restart development drilling in the second half of the year. We are increasing our capital budget by approximately $40 million this year to focus on the Cardium and Alberta Viking.

We conducted a preliminary review of our 2017 development plans and anticipate spending up to $150 million in total capital, including decommissioning expenditures next year. The majority of the spending focus will be on primary and integrated development in the Cardium area. We expect to continue primary development of the Alberta Viking and maintain production levels in Peace River. We expect the 2017 program will be fully funded through funds flow from operations and will deliver core production growth of at least 10% from the fourth quarter of 2016 to the fourth quarter of 2017.

Cardium

In the Cardium, we plan to drill two wells in the J-Lease area of the Pembina and three wells in the Willesden Green area in the second half of 2016.

In the J-Lease area, our first quarter project to replace seven kilometers of pipeline to improve reliability of the gas gathering system has continued to generate positive results. Since completion of the project, production reliability in the area has improved. We plan to drill two wells in the area in the second half of the year. These wells are located in close proximity to wells drilled last year that continue to exceed expectations. Waterflood implementation through the cemented liner system is proceeding in the J-Lease area in the second half of 2016 to further support our existing well base, and is expected to improve overall project economics.

In the Crimson Lake area of Willesden Green, we plan to drill and complete three wells in the second half of the year. An existing well will be converted to a water injector well in order increase reservoir pressure and support production from offsetting wells. Our Crimson wells drilled in the fourth quarter of last year continue to perform well ahead of the type curve, making these wells some of our most productive Cardium wells drilled to date.

Alberta Viking

In the Alberta Viking, we plan to drill 11 wells in the Esther area in the second half of 2016. The 11 wells will be drilled and completed using a longer one-mile wellbore design. This lateral design was previously used in the Dodsland area of the Viking in the first quarter of 2016, which led to reductions in finding and development costs. We expect our technical expertise and experience in the Saskatchewan Viking will directly transfer into success in our second half Alberta Viking program.

Peace River

In collaboration with our joint venture partner, we are running a two-rig program in the Peace River area this year. In the second quarter, we drilled and brought on production two wells (1.1 net), bringing our well on production well count to 12 wells (6.6 net) for the year. We expect to drill 19 wells (10.5 net) in the second half of 2016. Approximately 90 percent of our working interest expenditures continue to be paid by our partner.

In the second quarter, we entered into a multi-year gas supply agreement with a subsidiary of Kineticor Resources Corp. in support of a proposed 100MW power plant in the Peace River area of Alberta. Upon completion, this power project will allow us to meet our associated gas conservation targets in the area and will significantly reduce our environmental impact.

Senior Secured Debt

In the second quarter, we closed asset dispositions for total proceeds of approximately $1.3 billion, reducing our Net Debt to approximately $566 million from $2.1 billion at year-end 2015, which is outlined as follows:





As at

As at

(millions)

June 30, 2016

December 31, 2015

Syndicated bank facility and senior notes

$1,535

$1,940

Cash

($1,003)

($2)

Working capital deficiency (1) (2)

$34

$184

Net debt

$566

$2,122

Disposition proceeds subsequent to the second quarter of 2016

($75)

-

Pro-forma net debt

$491

$2,122


(1)

Includes Accounts receivable, Other current assets and Accounts payable and accrued liabilities.

(2)

Includes $3 million of working capital surplus included in Assets held for sale.

 

Subsequent to the quarter, we entered into agreements to sell an additional $75 million in non-core assets further decreasing our pro-forma Net Debt to approximately $491 million.

We continue to remain in compliance with all our financial covenants at June 30, 2016, including the Senior Debt to EBITDA covenant that was 3.9 times, relative to a 5.0 times limit. On June 30, 2016, we had additional excess cash totaling $374 million from disposition proceeds that we can offer as a pre-payment to our lenders at our discretion (Saskatchewan disposition proceeds already offered). Assuming these proceeds were offered to lenders as a pre-payment, pro-forma Senior Debt to EBITDA at June 30, 2016 would have been 2.3 times.

We anticipate remaining compliant with all our financial covenants for the foreseeable future and so we have removed the going concern note included in our first quarter 2016 financial statements.

The table below outlines the calculation of our Senior Debt to EBITDA covenant as at the end of the second quarter:




Twelve

months ended

(millions, except ratios)

June 30, 2016



Funds Flow

$115

Financing

$163

Realized gain on foreign exchange hedges on prepayments

($15)

Realized foreign exchange loss – debt prepayments

$79

Restructuring expenses

$39

EBITDA

$381

EBITDA contribution from assets sold (1)

($145)

EBITDA as defined by debt covenants

$236



Total senior notes

$1,193

Syndicated bank facility advances

$342

Total long-term debt

$1,535

Repayment from disposition proceeds (2)

$(627)

Letters of credit – financial (3)

$9

Total senior debt

$917



Senior Debt to EBITDA

3.89x 


(1)

Consists of EBITDA contributions from assets that have been disposed in the prior 12 months.

(2)

Was offered to noteholders prior to June 30, 2016 and repaid in July 2016.

(3)

Letters of credit that are classified as financial are included in the Senior Debt calculation per the debt agreements.

 

In June 2016, upon the close of the Company's Saskatchewan Viking disposition, the Company offered the $967 million of net proceeds received from this disposition for prepayment of outstanding senior notes and repayment of indebtedness on the Company's syndicated bank facility on a pro rata basis. The offer was fully accepted and the pro rata syndicated bank facility allocation of $340 million was repaid in late June 2016. The remaining $627 million was subsequently prepaid in July 2016 to holders of its senior notes. This pre-payment excluded the above-mentioned $374 million of cash on hand at June 30, 2016 that we still have the ability to offer as a pro rata pre-payment to our lenders in the future.

Updated Hedging Position

Our hedging program continues to help reduce the volatility of our funds flow from operations, and thereby improves our ability to align capital programs going forward. We target having hedges in place for approximately 25 percent to 40 percent of our crude oil exposure, net of royalties, and 40 percent to 50 percent of our gas exposure, net of royalties.

Our positions as of August 4, 2016 are as follows:










Q3 2016

Q4 2016

Q1 2017

Q2 2017

Q3 2017

Q4 2017

2018

Oil Volume (bbl/d)

6,000

6,000

3,000

-

-

-

-

C$ WTI Price (C$/bbl)

$71.07

$71.24

$69.37

-

-

-

-

Gas Volume (mmcf/d)

19

19

17

15

13

11

4

AECO Price (C$/mcf)

$2.96

$2.96

$3.02

$2.73

$2.74

$2.99

$2.89

 

Updated 2016 Guidance and 2017 Preliminary Look

Due to the additional financial flexibility afforded the Company through the debt reduction efforts to date, and supported by our high confidence in the economic potential of our core assets, we will be resuming development in the Cardium and Alberta Viking in the second half of 2016. We are increasing our full year capital budget by approximately $40 million to $90 million, plus $15 million allocated to decommissioning expenditures. As a result, we expect to increase our 2016 exit production by approximately 3,000 boe per day. Our 2016 capital budget will be fully paid for by full year funds flow from operations.

We forecast full year 2016 production to average 55,000 – 57,000 boe per day in total, prior to the effect any dispositions subsequent to the second quarter. Full year production is expected to average between 22,000 - 24,000 boe per day in our core areas. Full year corporate operating costs are forecasted to average between $13.50 and $14.50 per boe and G&A costs are forecasted to average between $2.50 and $2.90 per boe.

Our guidance for the 2016 is as follows:

Metric


Guidance Range

Average Corporate Production (1)

boe/d

55,000 – 57,000

Average Core Area Production

boe/d

22,000 – 24,000




E&D Capital Expenditures

$ millions

$90

Decommissioning Expenditures

$ millions

$15




Corporate Operating Costs (1)

$/boe

$13.50 – 14.50

G&A Costs

$/boe

$2.50 – $2.90




(1) Prior to the effect of any dispositions subsequent to the second quarter.

 

We have conducted a review of our preliminary 2017 plans and anticipate spending up to $150 million in total capital, including decommissioning expenditures, next year. The Cardium will remain the foundation of our development program supported by incremental growth in the Alberta Viking and meaningful cash generation at Peace River.  We expect next year's program will deliver core production growth of at least 10% from the fourth quarter of 2016 to the fourth quarter of 2017 and will be fully paid for by funds flow from operations.

Conference Call and Webcast Details

A conference call and webcast presentation will be held to discuss our second quarter results at 9:00am MT (11:00am ET) on Thursday, August 4, 2016.

To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (toll-free). This call will be broadcast live on the Internet and may be accessed directly at the following URL:

http://event.on24.com/r.htm?e=1227225&s=1&k=457F15D57D0452CCBB474A66CC24EF0E

Additional Reader Advisories 

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, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Non-GAAP Measures

This news release includes non-GAAP measures not defined under International Financial Reporting Standards ("IFRS") including funds flow, funds flow from operations, funds flow per share-basic, funds flow per share-diluted, funds flow from operations per share-basic, funds flow from operations per share-diluted, netback, EBITDA and gross revenues. Such terms are explained under the heading "Non-GAAP Measures" in the attached Management's Discussion and Analysis. 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.

Forward-Looking Statements

Certain statements contained in this press release 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", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are 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: that we are well on our way to completing the repositioning of our Company as a very focused, very profitable, liquids growth story in western Canada; that the deferred discretionary expenses, primarily related to turnarounds and workover activities, will result in a modest increase in operating costs in the second half of the year, that our markedly improved capital structure positions us competitively with our peers in terms of all significant debt metrics, that we will continue to streamline and high-grade the remainder of our portfolio this year in the final steps of our transformation into a leading Alberta oil producer, that we expect to dispose of assets with associated production of approximately 20,000 boe per day and generate between $100 million and $200 million in additional proceeds by the end of 2016 and that we remain confident in our ability to sell these assets, that we will take full advantage of our improved financial flexibility now afforded to us and are getting back to work on our future, that we are increasing our capital expenditure program by approximately $40 million (plus $15 million allocated for decommissioning expenditures), fully paid for by full year funds flow from operations, to restart development in the Cardium and Alberta Viking, planning to drill 5 wells in the Cardium, 11 wells in the Alberta Viking, and 19 (10.5) gross wells in the Peace River area, the expectation that our second-half drilling program to add approximately 3,000 boe per day to our 2016 exit production and set us up for continued growth into next year, that we anticipate spending approximately $150 million in total capital, including decommissioning expenditures, next year, that the Cardium will remain the foundation of our development program supported by incremental growth in the Alberta Viking and meaningful cash generation at Peace River, that next year's program will deliver core production growth of at least 10% from the fourth quarter of 2016 to the fourth quarter of 2017 and will be fully paid for by funds flow from operations, that our second half program sets the stage for a long term vision of a top quartile Company with consistent production growth of at least 10% annually, fully funded by funds flow from operations,  operating costs of $10 to $12 per boe, and low leverage metrics, that we expect to remain compliant with our financial covenants as we move forward, that we can offer, at our discretion, $374 million from disposition proceeds to our lenders and that we anticipate applying this cash to reduce our outstanding debt balance during the second half of the year, that the estimated proceeds from disposition of non-core assets sales with agreements entered into are approximately $75 million with associated average production of 6,000 boe per day, that we expect full year 2016 corporate production to average 55,000 – 57,000 boe per day in total, prior to the effect of additional dispositions, and 22,000 – 24,000 boe per day in our core areas, that our full year corporate operating costs are expected to average between $13.50 and $14.50 per boe and full year G&A costs are expected to average between $2.50 and $2.90 per boe, that Penn West's assets are able to deliver strong economic returns in the current commodity price environment and supports further development of its core plays in the Cardium and Alberta Viking, which remain profitable on a full cycle basis, that the majority of the spending focus will be on primary and integrated development in the Cardium, that we expect to continue primary development of the Alberta Viking and maintain production levels in Peace River, that in the Cardium we plan to drill two wells in the J-Lease area of the Pembina and three wells in the Willesden Green in the second half of 2016, that the waterflood implementation through the cemented liner system is proceeding in the J-Lease area in the second half of 2016 to further support our existing well base, which is expected to improve overall project economics, that in the Willesden Green area we plan to drill and complete three wells and an existing well is set to be converted to a water injector in order improve waterflood performance and support our existing well base, that the 11 wells to be drilled in the Ester area will be drilled and completed using a longer one-mile wellbore design, the expectation that our technical expertise and experience in the Saskatchewan Viking will directly transfer into success in our second half Alberta Viking program, that the completion of the Peace River power project will allow us to meet our associated gas conservation targets in the area and will significantly reduce our environmental impact, that we anticipate remaining compliant with all our financial covenants for the foreseeable future which has resulted in the removal of our going concern note disclosure that was included in our first quarter 2016 financial statements; that our hedging program continues to help reduce the volatility of our funds flow from operations, thereby improve our ability to align capital programs going forward, targeting certain hedges to be in place for our crude oil and gas exposure, and the 2016 guidance for the E&D Capital Expenditures and Decommissioning Expenditures. 

The forward-looking information is based on certain key expectations and assumptions made by Penn West, including expectations and assumptions concerning: prevailing and future commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the availability and cost of labour and services; the state of the economy and the exploration and production business; the availability and cost of financing; and ability to market oil and natural gas successfully.

Although Penn West believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Penn West can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; the possibility that we breach one or more of the financial covenants pursuant to our amending agreements with the syndicated banks and the holders of our senior, unsecured notes; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; reliance on third parties; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.

Additional information on these and other factors that could affect Penn West, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein) , Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Penn West's website.

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 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.

See also "Forward-Looking Statements" in the attached Management's Discussion and Analysis.

MANAGEMENT'S DISCUSSION AND ANALYSIS
For the three and six months ended June 30, 2016

This management's discussion and analysis of financial condition and results of operations ("MD&A") of Penn West Petroleum Ltd. ("Penn West", the "Company", "we", "us", "our") should be read in conjunction with the Company's unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2016 (the "Consolidated Financial Statements") and the Company's audited consolidated financial statements and MD&A for the year ended December 31, 2015. The date of this MD&A is August 3, 2016. All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise. 

Certain financial measures such as funds flow, funds flow from operations, funds flow per share-basic, funds flow per share-diluted, funds flow from operations per share-basic, funds flow from operations per share-diluted, netback, EBITDA and gross revenues included in this MD&A do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. This MD&A also contains oil and gas information and forward-looking statements. Please see the Company's disclosure under the headings "Non-GAAP Measures", "Oil and Gas Information", and "Forward-Looking Statements" included at the end of this MD&A. 

Quarterly Financial Summary
(millions, except per share and production amounts)(unaudited)


June 30

Mar. 31

Dec. 31

Sep. 30

June 30

Mar. 31

Dec. 31

Sep. 30

Three months ended (1)  

2016

2016

2015

2015

2015

2015

2014

2014

Gross revenues (2)

$

209

$

231

$

273

$

295

$

360

$

340

$

473

$

589

Funds flow from operations

55

47

39

48

85

77

146

235


Basic per share

0.11

0.09

0.08

0.10

0.17

0.15

0.29

0.47


Diluted per share

0.11

0.09

0.08

0.10

0.17

0.15

0.29

0.47

Funds flow

5

89

7

14

47

112

137

231


Basic per share

0.01

0.18

0.01

0.03

0.09

0.22

0.28

0.47


Diluted per share

0.01

0.18

0.01

0.03

0.09

0.22

0.28

0.47

Net loss 

(132)

(100)

(1,606)

(764)

(28)

(248)

(1,772)

(15)


Basic per share

(0.26)

(0.20)

(3.20)

(1.52)

(0.06)

(0.49)

(3.57)

(0.03)


Diluted per share

(0.26)

(0.20)

(3.20)

(1.52)

(0.06)

(0.49)

(3.57)

(0.03)

Dividends declared

-

-

-

5

5

5

70

69


Per share

$

-

$

-

$

-

$

0.01

$

0.01

$

0.01

$

0.14

$

0.14

Production









Liquids (bbls/d) (3)

41,848

53,012

53,339

55,323

63,222

65,343

64,124

64,687

Natural gas (mmcf/d)

130

144

144

161

168

177

198

217

Total (boe/d)

63,568

77,010

77,398

82,198

91,164

94,905

97,143

100,839

















(1)

Certain comparative figures have been reclassified to correspond with current period presentation.

(2)

Includes realized gains and losses on commodity contracts and excludes gains and losses on foreign exchange hedges.

(3)

Includes crude oil and natural gas liquids.

 

Calculation of Funds Flow and Funds Flow from Operations

(millions, except per share amounts)

Three months ended
June 30

Six months ended
June 30

2016

2015

2016

2015

Cash flow from operating activities

$

(56)

$

(67)

$

5

$

89

Change in non-cash working capital


59


109


85


54

Decommissioning expenditures


2


5


4


16

Funds flow


5


47


94


159

Monetization of foreign exchange contracts


-


(19)


(32)


(63)

Settlements of normal course foreign exchange contracts


6


(23)


6


(25)

Monetization of transportation commitment


-


-


(20)


-

Realized foreign exchange loss – debt prepayments


-


44


-


44

Realized foreign exchange loss – debt maturities


36


30


36


36

Carried operating expenses (1)


3


3


7


6

Restructuring charges


5


3


11


5

Funds flow from operations (2)

$

55

$

85

$

102

$

162










Per share – funds flow










Basic per share

$

0.01

$

0.09

$

0.19

$

0.32


Diluted per share


0.01


0.09


0.19


0.32

Per share – funds flow from operations










Basic per share


0.11


0.17


0.20


0.32


Diluted per share

$

0.11

$

0.17

$

0.20

$

0.32


(1)

The effect of carried operating expenses from the Company's partner under the Peace River Oil Partnership.

(2)

Certain comparative figures have been reclassified to correspond with current period presentation.

 

The decrease in funds flow from the comparative periods was mainly due to lower revenues as a result of a weaker commodity price environment and lower production volumes due to the Company's active disposition program. Over the past year, the Company has been successful in closing a number of asset sales which has significantly improved its financial position.  

During the second quarter of 2016, Penn West repaid senior notes in aggregate of US$141 million (2015 - US$165 million) as part of normal course maturities. As the Canadian dollar has weakened relative to the US dollar from the issue date of the senior notes to the settlement date, a realized foreign exchange loss was recorded.

In early 2016, the Company monetized a total of US$115 million of foreign exchange forward contracts on senior notes and permanently disposed of a pipeline commitment and received $20 million of proceeds from the sale.

Business Strategy

In the second quarter of 2016, the Company closed a key asset disposition, resulting in the sale of all of its Saskatchewan assets for cash consideration of $975 million, subject to closing adjustments. The combination of this transaction and several other dispositions in 2016 has resulted in total disposition proceeds to date of $1.3 billion. These successful asset sales have significantly improved the Company's balance sheet and resulted in compliance with all senior debt financial covenants at June 30, 2016 and it expects to remain in compliance through 2016 and the foreseeable future.

During the second half of 2016 the Company will continue to progress on its transformational strategy, with "Phase 2" of its disposition strategy, by high-grading assets and streamlining operations to three core areas all within Alberta including the Cardium, Alberta Viking and Peace River. The main focus of Phase 2 will be to improve the Company's long-term cost structure by removing peripheral properties outside its core areas which will decrease both unit operating costs and abandonment liabilities. Subsequent to the end of the second quarter, the Company has advanced on Phase 2 by entering into agreements to dispose properties with associated average production of approximately 6,000 boe per day for total proceeds of approximately $75 million. Thus far, the temporary regulations implemented by the Alberta Energy Regulator related to liability thresholds on acquisitions have not impacted the Company's ability to transact, however, it will continue to monitor this as it progresses through Phase 2. Upon completion of Phase 2, the Company believes its asset base will continually grow reserves, increase organic production by at least 10 percent on annual basis and increase funds flow from operations under the current commodity price environment. With Phase 2 well under way, the Company is on track to restart development in the second half of 2016 and deliver sustainable and profitable organic growth.

Business Environment

The following table outlines quarterly averages for benchmark prices and Penn West realized prices for the last five quarters.


Q2 2016

    Q1 2016

Q4 2015

Q3 2015

Q2 2015

Benchmark prices












WTI crude oil ($US/bbl)

$

45.59

$

33.45

$

42.18

$

46.43

$

57.94


Edm mixed sweet par price (CAD$/bbl)


54.70


40.67


52.85


56.17


67.93


NYMEX Henry Hub ($US/mcf)


1.95


2.09


2.27


2.77


2.64


AECO Index (CAD$/mcf)


1.32


1.97


2.56


2.85


2.66












Penn West average sales price (1)












Light oil (CAD$/bbl)


53.48


37.44


50.20


52.60


64.56


Heavy oil (CAD$/bbl)


25.18


14.76


25.40


31.20


46.44


NGL (CAD$/bbl)


18.05


12.75


19.53


15.24


17.40


Total liquids (CAD$/bbl)


42.98


29.86


42.16


44.83


55.85


Natural gas (CAD$/mcf)


1.42


1.96


2.54


2.99


2.78












Benchmark differentials












WTI - Edm Light Sweet ($US/bbl)


(3.07)


(3.69)


(2.46)


(3.42)


(2.86)


WTI - WCS Heavy ($US/bbl)

$

(13.30)

$

(14.24)

$

(14.49)

$

(13.27)

$

(11.59)



(1)

Excludes the impact of realized hedging gains or losses.

 

Crude Oil

Crude oil prices increased through the second quarter as there was evidence of reduced supply due to the prolonged low commodity price environment. Additionally, supply disruptions in Canada and Nigeria contributed to the increase. WTI prices increased from a low of US$36 per barrel early in the second quarter to a peak of US$52 per barrel in June before settling at just under $50 per barrel by quarter end. 

Canadian light oil differentials continued to strengthen in the second quarter, supported by a disruption in light synthetic crude supply for the last half of the quarter as a result of the wildfires in Fort McMurray. Similarly, Canadian heavy oil differentials tightened during the quarter as nearly one million barrels per day of production was offline for a period as a result of the Fort McMurray wildfire.

As at June 30, 2016, the Company had the following crude oil hedging positions in place:

Reference Price

Term

Price ($/Barrel)

Volume (Barrels/day)

WTI

Jul 2016 – Dec 2016

CAD $72.08

5,000

WTI

Jul 2016 – Sep 2016

CAD $66.05

1,000

WTI

Oct 2016 – Dec 2016

CAD $67.05

1,000

WTI

Jan 2017 – Mar 2017

CAD $69.37

3,000

 

Natural Gas

NYMEX Henry Hub natural gas prices strengthened throughout the second quarter as warmer than average temperatures across North America led to increased gas demand for power generation. The Henry Hub prompt month price started the quarter at US$1.96 per mcf and ended at US$2.92 per mcf.

AECO prices failed to follow the improvement in NYMEX prices as the loss of oil sands production early in the quarter due to forest fires resulted in a significant decrease in intra-Alberta demand as storage levels increased. Outages on the TransCanada Pipeline system restricted supply and partially mitigated the lost demand while the return of oil sands production later in the quarter helped to strengthen prices entering the third quarter. The second quarter began with April spot prices trading near $1.00 per mcf before climbing to approximately $2.25 per mcf by the end of June.

Penn West had the following natural gas hedging positions in place as at June 30, 2016. 

Reference Price

Term

Price ($/mcf)

Volume (mcf/day)

AECO

Jul 2016 – Dec 2016

CAD $3.05

14,000

AECO

Jul 2016 – Dec 2016

CAD $2.69

4,700

 

Subsequent to June 30, 2016, the Company entered into additional AECO natural gas hedges as follows:

  • 17,100 mcf per day of production in the first quarter of 2017 at $3.02 per mcf,
  • 15,200 mcf per day of production in the second quarter of 2017 at $2.73 per mcf,
  • 13,300 mcf per day of production in the third quarter of 2017 at $2.74 per mcf,
  • 11,400 mcf per day of production in the fourth quarter of 2017 at $2.99 per mcf, and
  • 3,800 mcf per day of production in the year of 2018 at $2.89 per mcf.

Average Sales Prices


Three months ended
June 30

Six months ended
June 30

2016

2015

%
change

2016

2015

%

change












Light oil (per bbl)

$

53.48

$

64.56

(17)

$

44.37

$

57.10

(22)

Commodity gain (loss) (per bbl) (1)


8.80


(1.31)

>100


10.19


0.44

>100

Light oil net (per bbl)


62.28


63.25

(2)


54.56


57.54

(5)












Heavy oil (per bbl) 


25.18


46.44

(46)


19.75


38.06

(48)












NGL (per bbl) 


18.05


17.40

4


14.89


18.79

(21)












Natural gas (per mcf) 


1.42


2.78

(49)


1.70


2.93

(42)

Commodity gain (per mcf) (1)


0.25


0.08

>100


0.27


0.70

(61)

Natural gas net (per mcf)


1.67


2.86

(42)


1.97


3.63

(46)












Weighted average (per boe) 


31.20


43.84

(29)


27.38


39.53

(31)

Commodity gain (loss) (per boe) (1)


4.27


(0.49)

>100


5.08


1.51

>100

Weighted average net (per boe)

$

35.47

$

43.35

(18)

$

32.46

$

41.04

(21)



(1)

Realized risk management gains and losses on commodity contracts are included in gross revenues.

 

RESULTS OF OPERATIONS

Production


Three months ended

June 30

Six months ended

June 30

Daily production

2016

2015

%

change

2016

2015

%

change

Light oil (bbls/d)

27,148

44,195

(39)

31,433

45,021

(30)

Heavy oil (bbls/d)

11,427

11,947

(4)

11,934

12,418

(4)

NGL (bbls/d)

3,273

7,080

(54)

4,064

6,838

(41)

Natural gas (mmcf/d)

130

168

(23)

137

172

(20)

Total production (boe/d)

63,568

91,164

(30)

70,289

93,024

(24)

 

During the second quarter of 2016, the Company continued to experience the positive effects of its drilling program completed in late 2015 where it has seen well performance higher than historical type curve estimates. Additionally, fewer wells were shut-in than previously anticipated, which also contributed to the Company's production results coming in ahead of expectations. Offsetting these production gains, the Company closed several non-core asset dispositions during the quarter, notably the Slave Point disposition in mid-April which had associated average production of approximately 3,900 boe per day and the Saskatchewan Viking disposition in late June which had associated average production of approximately 13,700 boe per day. This disposition activity has resulted in the Company updating its 2016 average production target to 55,000 – 57,000 boe per day from 60,000 – 64,000 boe per day.

Production levels have decreased from the comparative periods as a result of these aforementioned transactions and several other property dispositions that were closed in 2015 and 2016 as the Company progressed on its strategy to strengthen its balance sheet and reduce debt levels. 

Subsequent to June 30, 2016, the Company signed definitive sales agreements on properties with associated average production of approximately 6,000 boe per day. Penn West expects these transactions to close prior to the end of the third quarter of 2016.

Netbacks


Three months ended June 30


2016

2015


Light Oil and
NGL

Heavy Oil

Natural Gas

Combined

Combined


(bbl)

(bbl)

(mcf)

(boe)

(boe)












Operating netback:












Sales price (1)

$

49.66

$

25.18

$

1.42

$

31.20

$

43.84


Commodity gain (loss) (2)


7.86


-


0.25


4.27


(0.49)


Royalties


(3.60)


(2.19)


0.73


(0.63)


(4.72)


Transportation


(1.55)


(2.45)


(0.34)


(1.89)


(1.40)


Operating costs (3)


(15.53)


(11.22)


(1.59)


(12.70)


(18.15)

Netback

$

36.84

$

9.32

$

0.47

$

20.25

$

19.08














(bbls/d)


(bbls/d)


(mmcf/d)


(boe/d)


(boe/d)

Production


30,421


11,427


130


63,568


91,164



(1)

Excluded from the netback calculation during the second quarter was $3 million of other income (2015 - $nil) including sulphur sales.

(2)

Realized risk management gains and losses on commodity contracts.

(3)

Includes the effect of carried operating expenses from the Company's partner under the Peace River Oil Partnership of $3 million or $0.52 per boe (2015 - $3 million or $0.36 per boe).

 

The Company's netbacks continued to be affected by the weak commodity price environment resulting in a significant decline in sales price year-over-year. However, netbacks have increased from the prior year due to successful cost reductions which resulted in lower operating costs, increased commodity gains due to the Company's active hedging program and a reduction in royalties due to the lower commodity price environment. During the second quarter of 2016, Penn West received its annual gas cost allowance invoice which positively impacted the natural gas royalty rate.


Six months ended June 30


2016

2015


Light Oil and
NGL

Heavy Oil

Natural Gas

Combined

Combined