Market Overview

Perpetual Announces 2017 Exit Rate Growth of 54% and Provides Operations Update, Reports Year-End Reserves Replacing 248% of Production and Revises 2018 Capital Plan and Outlook

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CALGARY, Feb. 7, 2018 /PRNewswire/ - (TSX:PMT) – Perpetual Energy Inc. ("Perpetual", or the "Company") is pleased to announce its year-end 2017 production exit rate (average for the month of December) of 12,300 boe/d, attaining year-over-year exit rate growth of 54%. The Company invested $19.0 million in exploration and development activities during the fourth quarter of 2017 and grew production 14% quarter-over-quarter. Production and operating costs continued the positive trend established through 2017, averaging $3.45/boe for the fourth quarter and $4.52/boe for 2017, down 33% from full year 2016.

In 2017, Perpetual focused investment in its core producing assets at East Edson and Mannville, adding proved plus probable reserves to replace 248% of annual production and grow the value of proved plus probable reserves year-over-year, as reported by the independent engineering firm McDaniel and Associates Consultants Ltd. ("McDaniel"). The quality of Perpetual's assets and positive momentum to drive operational and execution excellence in its core operating areas are demonstrated by the highlights below:

  • Total proved plus probable reserves grew by 9% to 66.6 MMboe, up 5.3 MMboe after 2017 production of 3.6 MMboe. Importantly, the Company grew total proved reserves by 22% to 42.8 MMboe (64% of total proved plus probable reserves) and doubled its proved developed producing reserves to 15.9 MMboe. Proved plus probable developed producing reserves were 20.5 MMboe at December 31, 2017, 44% higher than year-end 2016.

  • Proved plus probable developed producing reserves were 20.5 MMboe at December 31, 2017, 44% higher than year-end 2016.

  • Exploration and development capital spending of $73.0 million in 2017 resulted in finding and development ("F&D") costs of $6.16/boe on a proved plus probable basis, and finding, development and acquisition costs ("FD&A") of $5.98/boe, both including changes in future development capital ("FDC"). Combining with a 2017 operating netback of $14.35/boe, the Company achieved a proved plus probable FD&A recycle ratio of 2.4:1.

  • The net present value ("NPV") of Perpetual's total proved plus probable reserves (discounted at 10%) before income tax, grew by 8% to $409.9 million (2016 - $380.7 million), despite a decrease in McDaniel's forecast for both oil and natural gas prices at year-end 2017.

  • Based on McDaniel's commodity price forecasts, Perpetual's reserve-based net asset value ("NAV") (discounted at 10%) at year-end 2017 is estimated at $336.5 million ($5.68 per share).

Finally, in active management of the recent decline in the forward market for near-term AECO natural gas prices, Perpetual today announces several important steps taken to maximize profitability, preserve the value of its reserves and manage risk:

  • Perpetual reduced its exposure to AECO natural gas prices through the market diversification contracts entered into during the third quarter of 2017 and has now secured fixed price forward sales contracts on its remaining expected 2018 AECO natural gas sales volumes, net of royalties.

  • Further, Perpetual's Board of Directors have approved a revised 2018 capital plan totaling $23 to $27 million, a 30% reduction to capital spending from the plan announced on November 10, 2017. The revised plan is designed to prudently defer development of the Company's East Edson natural gas asset to ensure maximum returns from development of the reserves and re-allocate capital to heavy oil prospects in its diversified portfolio of opportunities. At the current forward commodity price market, the revised capital spending plan is expected to result in 2018 adjusted funds flow in excess of capital spending and obligations, allowing for debt repayment and other opportunities.

OPERATIONS UPDATE

During the fourth quarter of 2017, capital spending totaled $19.0 million as previously forecast, more than 90% directed to the Company's liquids-rich gas property at East Edson. An additional $0.9 million was spent on well abandonment and reclamation work to reduce decommissioning obligations.

The single rig drilling program at East Edson continued through the fourth quarter, resulting in the drilling of three (3.0 net) wells, including a second extended reach horizontal ("ERH") well. A third ERH well will be rig released in the first quarter of 2018 to finish the East Edson drilling program. The first two ERH wells were completed and tied in during the fourth quarter while the remaining two wells were completed in January 2018. Completion operations for the third ERH well, originally scheduled for the first quarter of 2018, have been deferred to the fourth quarter of 2018, anticipating stronger future natural gas prices to maximize profitability.

The first ERH well at 4-23-51-16W5 represented the highest deliverability well drilled to date by Perpetual at East Edson with a thirty day average initial productivity ("IP30") of 15.6 MMcf/d of natural gas plus associated liquids based on field estimates, 75% higher than the length-adjusted type curve contained in the 2017 year-end McDaniel reserve report. The second ERH well, which is still under test and not optimized, appears to be below the length-adjusted type curve. The sum of the two wells is anticipated to exceed McDaniel's proven plus probable expectations.

In the fourth quarter of 2017, compression was added at the 100% owned and operated West Wolf Lake 10-3 plant, to align compression and process capacity at the facility, bringing the plant capacity to 65 MMcf/d, and area capacity to 78 MMcf/d, including the 15% working interest capacity held at a third-party operated facility in Rosevear. This expansion was completed in December 2017 for $2.1 million, on budget and three months ahead of schedule, to accommodate the accelerated availability of increased firm transportation on TCPL to 78 MMcf/d from April 1, 2018 to December 17, 2017.

Eleven (11.0 net) of the wells drilled in 2017 had an average 1,700 meters horizontal length and pioneered a new monobore well design. This new design, coupled with lower service costs, reduced the total cost of a typical Edson well to $4.2 million (inclusive of drilling, completion, equipment and tie-in), driving capital efficiencies from an average $11,000 per boe/d during 2014 to 2016 to $8,600 per boe/d based on first 12-month average production as per McDaniel's proved developed producing forecast, despite operational difficulties on one well which had a significantly higher capital efficiency ratio. Two (2.0 net) additional wells drilled in 2017 were designed to test the application of ERH wells for future development of the Wilrich reserves and were successfully drilled to 2,460 meters and 3,489 meters in length, with the third ERH well rig released in the first quarter of 2018 at 2,953 meters. Preliminary results suggest that capital efficiencies will be further reduced through this development approach.

Capital spending on heavy oil projects in Mannville during the fourth quarter of 2017 included waterflood projects and well optimization activities with $1.0 million spent. In January, construction of additional water handling and disposal facilities are underway and the first of a four (4.0 net) well (10 multi-lateral legs) drilling program was spud on January 31, 2018.

Drilling activities in 2017 resulted in production from one new Sparky pool, and increased production in the I2I pool which has been under waterflood since late 2013. 2017 saw a marked reduction in base decline rates in heavy oil production at Mannville from an average of greater than 30% year-over-year declines in 2015 and 2016 to less than 10% through 2017 (excluding the impact of new drilling). This reduction in decline rates is attributable to successful waterflood performance, resulting in higher recovery of oil in place.

Fourth quarter 2017 operating expenses continued to trend downward to $3.45/boe. Reduced costs at both Mannville and East Edson improved area operating netbacks, and operating costs on a unit-of-production basis reached top decile performance at East Edson as production ramped up on a relatively fixed operating base.

2018 OUTLOOK

2018 Capital Spending

In response to material commodity market changes, Perpetual has revised its 2018 capital plan to preserve the value of its East Edson reserves by deferring any additional 2018 Wilrich formation development drilling and accelerate spending on highly economic heavy oil projects at Mannville, for a net reduction to the 2018 capital budget to $23 - $27 million. On November 10, 2017, the Company announced that the Board of Directors approved a capital spending program of $37 million for 2018, close to 75% concentrated in East Edson, developing natural gas reserves with liquids in the Wilrich formation, and 25% in Eastern Alberta, primarily targeting heavy oil development at Mannville. The forward average AECO and WTI prices for Calendar 2018 as of November 9, 2017 were $2.01 per GJ (US$3.09 per MMbtu NYMEX) and US$56.91 per bbl, respectively. The revised capital plan accounts for the wind down of gas focused drilling activities at East Edson and results in a modified capital plan with investment split more evenly between the two core operating areas and natural gas and oil commodities.

Although NYMEX natural gas prices have remained relatively steady as natural gas storage has been depleted through the winter to below historical levels driven by strong demand, the basis differential to Western Canada markets has widened and AECO forward natural gas prices have weakened materially over the same period. Perpetual's five year market diversification contracts that came into effect on November 1, 2017 have substantially mitigated the impact on adjusted funds flow of lower AECO prices, as the contracts appreciate in value with wider differentials to each of the five market price points. However, Perpetual measures economic returns for all new natural gas investments against current unhedged AECO strip pricing, as incremental volumes, net of royalties, would be effectively sold to this market. At the same time, the forward market for West Texas Intermediate oil has strengthened, translating into slightly stronger expected prices for Perpetual's blend of heavy oil, condensate and natural gas liquids ("NGL"). Currently, the forward average AECO and WTI prices for calendar 2018 as of February 6, 2018 are $1.35 per GJ and US$61.25 per bbl, respectively.

Perpetual's two core areas of operation provide a diversified portfolio of investment opportunities. The Company will remain nimble to reallocate spending between natural gas focused projects at East Edson and heavy oil projects depending on where the most profitable economics can be secured. For the first quarter, the one outstanding frac of the third ERH well at East Edson will be postponed until late in the third quarter of 2018. Perpetual will re-direct spending to its heavy oil development project of the Birch General Petroleum A pool in Mannville, including water handling and disposal facilities and a four well multi-lateral horizontal drilling program previously budgeted for the second half of 2018. Assuming continued weakness in AECO natural gas prices, the four-well East Edson drilling program previously planned for the third quarter of 2018 will be deferred pending stronger AECO natural gas prices. Three (2.3 net) development wells at Mannville are expected to proceed as planned in the third quarter, along with three to six (3.0 to 6.0 net) additional wells at Mannville to evaluate the future horizontal development potential of three undeveloped heavy oil pools.

The table below summarizes planned capital spending and drilling activities for the first and second half of 2018.

Exploration and Development Forecast Capital Expenditures


H1 2018

$ millions

# of wells

(gross/net)

H2 2018

$ millions

# of wells

(gross/net)

Total 2018

$ millions

# of wells

(gross/net)

West Central

8

1/1.0

3

0/0.0

11

1/1.0





6 - 9/5.3 –


10 - 13/9.3 –

Eastern

6

4/4.0

6 - 10

8.3

12 - 16

12.3





6-9/5.3 –


11 - 14/10.3 –

Total(1)(2)

14

5/5.0

9 - 13

8.3

23 - 27

13.3

(1)    

Excludes abandonment and reclamation spending of $2.0 to $2.5 million in 2018.

(2)    

Previous capital spending forecast released November 10, 2017 included forecast total exploration and development capital spending of $37 million. Please see news release dated November 10, 2017 for details.

 

Production Guidance

With the accelerated availability of increased firm transportation on TCPL, coupled with the capital re-allocation strategy to heavy oil, first quarter 2018 production is expected to average close to 13,300 boe/d, approximately 1,100 boe/d higher than previously forecast. Natural declines at East Edson will decrease natural gas and NGL production during the second and third quarters when AECO gas prices are expected to be at their lowest levels for the year. Then production will ramp up again with the planned late third quarter frac of the ERH well waiting on completion. Based on total exploration and development capital spending in 2018 of $23 to $27 million, Perpetual forecasts production to average approximately 11,500 boe/d for 2018 and forecasts to exit the year at approximately 10,700 boe/d (17% oil and NGL) as gas production at East Edson declines and Mannville heavy oil production ramps up driven by increased drilling and waterflood activity. While the growth in average daily production will be diminished from the original budget plan of 32%, year-over-year growth is still expected to be 17%, with a higher proportion of oil and NGL than previously forecast.

Marketing and Hedging Update

Concurrent with the sale of Perpetual's shallow gas properties on October 1, 2016, Perpetual entered into commodity price contracts whereby Perpetual was obligated to provide an AECO floor price of $2.58/GJ on 33,611 GJ/d through August 31, 2018. Perpetual's obligation has now been fixed at a cost of $8.5 million in 2018.

During the third quarter of 2017, Perpetual diversified its natural gas price exposure from AECO by entering into arrangements to effectively shift the sales point of 34.1 MMcf/d to a basket of five North American natural gas hub pricing points for a five year period commencing November 1, 2017, increasing to 39.0 MMcf/d commencing April 1, 2018. Based on current futures prices, these market diversification contracts will provide a significant premium over AECO prices in 2018 and provide significant diversification to Perpetual's natural gas pricing point exposure (net of royalties) as detailed below:

Market/Pricing Point


Natural gas

Estimated Proportion of

2018 Production(1)


AECO(1)                                               

0%


AECO fixed price

27%


Empress

5%


Dawn

11%


Michcon

7%


Chicago

18%


Malin

16%

Total natural gas

84%

Natural gas liquids - Condensate(1)

3%

Natural gas liquids - Other(1)

2%

Crude oil - Fixed(1)

3%

Crude oil - Floating(1)

8%

Total

100%

(1)

 Net of royalties.

 

Perpetual has in place a number of commodity hedges to increase certainty of 2018 adjusted funds flow by mitigating the effects of commodity price volatility.

Natural Gas

The following table provides a summary of natural gas physical and financial forward sales positions (net of related financial natural gas purchase contracts) in place as at February 6, 2018:

AECO





Term

Volume
(GJ/d)

Average price
($/GJ)(1)

Market prices
($/GJ)(2

Type of
contract

March 2018

17,500

$2.52

$1.38

Physical

April 2018 – October 2018

10,000

$2.06

$1.10

Financial

April 2018 – March 2019

10,000

$1.41

$1.38

Financial

September 2018 – March 2019

5,000

$1.40

$1.62

Physical

(1)

Average price calculated using weighted average price for net open contracts.

(2) 

Market prices are based on forward prices as of market close on February 6, 2018.


 

Crude Oil

The following tables provide a summary of crude oil contracts in place as at February 6, 2018:

Oil sales arrangements in USD$







Term

Volumes
(bbl/d)

Floor price
(US$/bbl)

Ceiling
price
(US$/bbl)

Fixed Price
(US$/bbl)

 

Market prices
(US$/bbl)(1)

 

Type of
contract

February – December 2018

500

$50.00

$59.20

$61.12

Collar

February – December 2018

250

$63.74

$61.12

Fixed Price

(1)

Market prices are based on forward WTI oil prices as of market close on February 6, 2018.

 

Basis differential contracts between WTI and WCS trading





Term

Volumes

(bbl/d)

WTI-WCS
differential
(US$/bbl)(1)

 

Market prices

(US$/bbl)(2)

 

Type of
contract

February – March 2018

750

($17.05)

($26.78)

Financial

April – June 2018

500

($14.45)

($26.79)

Financial

(1)

WTI-WCS differential price calculated using weighted average price for net open contracts; contracts settle at WTI index less a fixed basis amount.

(2)

Market prices are based on forward WTI-WCS differential prices as of market close on February 6, 2018.

 

Adjusted Funds Flow and Sensitivities

The following revised 2018 guidance assumptions, based on settled and forward 2018 market prices as at January 25, 2018 and operations assumptions as outlined above, have been used:

  • Exploration and development capital spending of $23 to $27 million;
  • 2018 average daily production of 11,500 boe/d (17% oil and NGL);
  • Calendar 2018 average NYMEX gas price of US$2.98 per MMbtu;
  • Calendar 2018 average West Texas Intermediate ("WTI") oil price of US$63.54 per bbl;
  • Calendar 2018 average Western Canadian Select ("WCS") differential of (US$23.83) per bbl;
  • Calendar 2018 average NYMEX to AECO basis differential of (US$1.77) per MMbtu;
  • Calendar 2018 average CAD/USD exchange rate of 1.235; and
  • 2018 cash costs, including royalties, of $13.00 to $14.00 per boe, increased slightly from previous outlook due to the impact of lower forecast production volumes on a mainly fixed cost structure.

Based on the capital spending plan and production assumptions outlined above, and the current forward market for oil and natural gas prices at market pricing points, Perpetual forecasts 2018 adjusted funds flow of $33 to $37 million ($0.56/share to $0.62/share) down from $35 to $40 million previously forecast in its news release dated November 10, 2017 due to lower forecast production and natural gas pricing.

Over the past year, natural gas prices at AECO have become disconnected from the North American market as resource development in the Western Canadian Sedimentary Basin has outpaced market access and market demand. Perpetual's market diversification contracts were put in place to mitigate the risk of lower AECO pricing due to widening of the basis differentials relative to various other markets and enable price participation in NYMEX-based markets. Incorporating the assumptions outlined above, and presuming NYMEX and AECO basis differentials remain constant to each of the diversified natural gas pricing points, Perpetual's estimated adjusted funds flow sensitivity to various commodity prices is as follows:

Projected 2018 Adjusted Funds Flow (1)(2)



Calendar 2018 NYMEX price ($US/MMbtu)

Calendar
2018

WTI price
($US/bbl)

($CAD millions)

$2.25

$2.50

$2.75

$3.00

$3.25

$3.50

$3.75

$45.00

20.7

22.8

24.8

26.9

29.0

31.1

33.2

$50.00

22.5

24.5

26.6

28.7

30.8

32.9

35.0

$55.00

25.3

27.4

29.5

31.6

33.7

35.8

37.8

$60.00

28.0

30.1

32.2

34.2

36.3

38.4

40.5

$65.00

29.8

31.9

33.9

36.0

38.1

40.2

42.3

$70.00

31.6

33.7

35.7

37.8

39.9

42.0

44.1

$75.00

33.4

35.4

37.5

39.6

41.7

43.8

45.9

(1)

Sensitivities assume non-AECO market price points adjust commensurately and the Calendar 2018 AECO basis and WCS differentials are fixed at US($1.77)/MMbtu and US($23.83)/bbl respectively.

(2)

The current settled and forward average NYMEX, WTI, NYMEX to AECO basis differential and WCS prices for Calendar 2018 as of February 6, 2018, were US$2.88/MMbtu, US$61.25/bbl, (US$1.73)/MMbtu, (US$25.60)/bbl respectively. The CAD/USD exchange rate for Calendar 2018 as at February 6, 2018 was 1.249.

 

The following additional sensitivities can be applied to estimate additional changes to projected 2018 adjusted funds flow:

  • For every $0.25 USD/MMbtu widening or increase (narrowing or decrease) in the Calendar 2018 NYMEX to AECO basis differential, adjusted funds flow increases (decreases) by $4.4 million;

  • For every $5.00 USD/bbl widening or increase (narrowing or decrease) in the Calendar 2018 WCS differential, adjusted funds flow decreases (increases) by $1.6 million; and

  • For every $0.01 increase (decrease) in the Calendar 2018 CAD/USD exchange rate, adjusted funds flow increases (decreases) by $0.9 million.

At the current forward market for natural gas and oil prices, 2018 adjusted funds flow is expected to exceed capital spending and other obligations. Year-end 2018 debt, net of the current market value of the Company's investment in shares of Tourmaline Oil Corp. ("TOU" – TSX) of close to $35 million, is forecast at $105 to $110 million, with a corresponding estimated net debt to trailing twelve months adjusted funds flow ratio of approximately 3.2 times.

2017 YEAR-END RESERVES

Year-end 2017 Reserve Highlights

  • Total proved plus probable reserves were 66.6 MMboe at December 31, 2017, up 5.3 MMboe (9%) from year-end 2016 after production of 3.6 MMboe.

  • Total proved producing reserves were 15.9 MMboe at December 31, 2017, up 99% from year-end 2016 and proved plus probable producing reserves were 20.5 MMboe at December 31, 2017, up 44% from year-end 2016.

  • Despite a decrease in McDaniel's forecast for both oil and natural gas prices, the NPV (discounted at 10%) ("NPV10") of the proved plus probable reserves increased by 8% at year-end 2017 to $409.9 million, highlighting the value growth created through demonstrated material operating cost reductions and enhanced capital efficiencies. The increase in value of the proved plus probable reserves was driven by strong well performance at both East Edson and Mannville and a 5% reduction to forecast future development capital ("FDC").

  • East Edson represented 92% (2016 – 93%) of total proved plus probable reserves at year-end 2017. The drilling of 13 (13.0 net) wells in 2017 more than compensated for production of close to 2.9 MMboe, increasing proved plus probable producing reserves by 49%. The plant expansion at East Edson completed in late 2017 provides company-owned infrastructure capacity and firm transportation alignment at 78 MMcfd. A revised development plan including the new ERH well design and higher production capacity, resulted in an overall reduction of future development capital while growing total proved plus probable reserves by 8%.

  • Production from heavy oil wells at Mannville of 0.4 MMboe was offset by upward technical revisions to proved plus probable reserves related to the positive impact of waterflood implementation during 2017. Total proved plus probable reserves were 3.3 MMboe at December 31, 2017, up 0.5 MMboe from year-end 2016. While Mannville heavy oil reserves account for just 5% of Perpetual's total proved plus probable reserves, this core area accounts for 9% of Perpetual's total proved developed producing reserves and 10% of total proved plus probable developed producing reserves.

  • On a commodity basis, oil and natural gas liquids ("NGL") represent 12% (11% at year-end 2016) of Perpetual's total proved plus probable reserves and 11% (11% at year-end 2016) of total proved reserves at December 31, 2017.

  • Positive technical proved reserve revisions in both East Edson and Mannville heavy oil assets offset total Company annual production of 3.6 MMboe by 284%, highlighting strong operational performance and drilling results from the Company's core assets.

  • Perpetual's NAV (discounted at 10%) at year-end 2017 was preserved at $336.5 million ($5.68 per share) as compared to $394.8 million ($7.33 per share) at year-end 2016, despite lower forecast commodity prices. See the detailed NAV calculation under the heading "NET ASSET VALUE".

Reserves Disclosure

Working interest reserves included herein refer to working interest reserves before royalty deductions. Reserves information is based on an independent reserves evaluation report prepared by McDaniel's with an effective date of December 31, 2017 (the "McDaniel Report"), and has been prepared in accordance with National Instrument 51-101 ("NI 51-101") using McDaniel's forecast prices and costs. Complete NI 51-101 reserves disclosure including after-tax reserve values, reserves by major property and abandonment costs will be included in Perpetual's Annual Information Form ("AIF"), when filed, and will be available on the Corporation's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com. Perpetual's reserves at December 31, 2017 are summarized below:

Working Interest Reserves at December 31, 2017(1)


Light and
Medium
Crude Oil
(Mbbl)

 

Heavy

Oil
(Mbbl)

 

Conventional
Natural Gas
(MMcf)

Natural Gas
Liquids

(Mbbl)

Oil

Equivalent
(Mboe)

Proved Producing

72

1,371

80,681

997

15,887

Proved Non-Producing

196

10,103

151

2,030

Proved Undeveloped

438

136,937

1,614

24,875

Total Proved

72

2,004

227,721

2,761

42,791

Probable Producing

11

445

22,995

295

4,583

Probable Non-Producing

73

4,568

34

868

Probable Undeveloped

472

97,845

1,577

18,357

Total Probable 

11

990

125,408

1,906

23,808

Total Proved plus Probable 

83

2,994

353,129

4,667

66,599

(1)

May not add due to rounding.

 

Total proved reserves at December 31, 2017 account for 64% (2016 – 57%) of total proved plus probable reserves. Proved producing reserves of 15.9 MMboe comprise 37% (2016 – 23%) of total proved reserves. Proved plus probable developed reserves of 23.4 MMboe represent 35% (2016 – 26%) of total proved plus probable reserves. The material increase in the percentage of producing and developed reserves at year-end 2017 relative to the prior year is primarily due to the impact of drilling at East Edson converting wells from undeveloped to developed, as well as an increased recognition in waterflood reserves in Mannville heavy oil.

Reserves Reconciliation

Working Interest Reserves(1)






 

Barrels of Oil Equivalent (Mboe)

 

Proved


 

Probable


Proved
and Probable

Opening Balance, December 31, 2016

35,096


26,186


61,283

Discoveries



Extensions and Improved Recovery

201


2,331


2,532

Technical Revisions

11,133


(4,736)


6,397

Acquisitions

160


19


179

Dispositions



Production

(3,599)



(3,599)

Economic Factors

(200)


8


(192)

Closing Balance, December 31, 2017

42,791


23,808


66,599

(1)

May not add due to rounding.

 

McDaniel's recorded net positive technical revisions of 6.4 MMboe related to performance on a proved plus probable basis in 2017. Positive technical revisions of 1.5 MMboe were attributed to improved performance of existing wells in both West Central and Eastern areas, and 4.9 MMboe were related to increases in individual reserve assignments in the East Edson area associated with the ERH locations and the reclassification of inventory locations to probable undeveloped reserves in the eight year development window.

The table below summarizes the FDC estimated by McDaniel's by play type to bring non-producing and undeveloped reserves to production.

Future Development Capital(1)








($ millions)

2018

2019

2020

2021

2022

Remainder

Total

Eastern Alberta Shallow Gas

1.0

0.2

1.2

Mannville Heavy Oil

6.6

3.3

9.9

East Edson Wilrich

32.8

41.6

39.4

40.1

41.3

142.1

337.3

Total

40.4

45.1

39.4

40.1

41.3

142.1

348.4

(1)

May not add due to rounding.

 

McDaniel's estimates the FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves, to be $348.4 million at December 31, 2017. Estimated FDC decreased by $19.2 million, down from $367.6 at year-end 2016, and $458.7 million at year-end 2015. On a proved plus probable basis, FDC decreased by $23.4 million related to the future development of reserves at East Edson and increased $4.2 million in the Mannville heavy oil area. Positive adjustments were related to improvements in capital efficiencies in East Edson due to changes in well design. ERH wells (2,000 – 3,500 meters in horizontal length) are modeled at higher total cost, but have improved capital efficiencies as higher production more than makes up for costs on a per meter basis. The increased reservoir coverage and higher per well rates due to the ERH wells utilized in the future development plan in the Wilrich formation at East Edson has reduced the total number of locations in the total proved plus probable eight year development plan to 63.3 net undeveloped locations (2016 – 72.7 net locations). The projects are forecast by McDaniel's to generate annual operating cash flow in excess of the annual FDC, making the projects self-funding.

RESERVE LIFE INDEX

Perpetual's proved plus probable reserves to production ratio, also referred to as reserve life index ("RLI"), was 13.2 years at year-end 2017 while the proved RLI was 9.1 years, based upon the 2018 production estimates in the McDaniel Report. The following table summarizes Perpetual's historical calculated RLI.

Reserve Life Index(1)






Year-end

2017

2016

2015

2014

2013

Total Proved

9.1

9.3

7.3

7.3

5.2

Total Proved plus Probable

13.2

15.1

11.9

11.9

8.6

(1)

Calculated as year-end reserves divided by year one production estimate from the McDaniel Report.

 

NET PRESENT VALUE OF RESERVES SUMMARY

Perpetual's oil, natural gas and NGL reserves were evaluated by McDaniel's using McDaniel's product price forecasts effective January 1, 2018 prior to provision for financial oil and natural gas price hedges, income taxes, interest, debt service charges and general and administrative expenses. The following table summarizes the NPV of funds flows from recognized reserves at January 1, 2018, assuming various discount rates: 

NPV of Reserves, before income tax(1)(2)





($ millions except as noted)

Undiscounted

5%

8%

10%

 

 

15%

 

Discounted
at

20%

Unit Value
Discounted

at
10%/Year

($/boe)(3)

Proved Producing

155.7

141.9

133.7

128.7

117.4

108.1

12.61

Proved Non-Producing

31.3

21.8

18.2

16.3

12.8

10.3

9.14

Proved Undeveloped

288.3

185.4

145.2

124.3

86.0

60.8

5.64

Total Proved

475.2

349.1

297.1

269.2

216.2

179.2

7.91

Probable Producing

80.1

53.4

43.3

38.1

29.0

23.1

10.22

Probable Non-Producing

12.2

7.6

6.2

5.5

4.3

3.6

7.21

Probable Undeveloped

285.3

160.4

117.7

97.1

62.6

42.7

5.77

Total Probable

377.6

221.3

167.1

140.7

96.0

69.4

6.90

Total Proved plus probable

852.8

570.4

464.2

409.9

312.1

248.6

7.40

(1)

January 1, 2018 McDaniel forecast prices and costs.

(2)

May not add due to rounding.

(3)

The unit values are based on net reserve volumes.

 

McDaniel's NPV10 estimate of Perpetual's total proved plus probable reserves at year-end 2017 was $409.9 million, up 8% from $380.7 million at year-end 2016. The increase in NPV10 reflected recycle ratios at East Edson driven by better well performance, combined with lower FDC in 2017, which offset the impact of lower forecast commodity prices. At a 10% discount factor, total proved reserves account for 66% (2016 – 55%) of the proved plus probable value. Proved plus probable producing reserves represent 41% (2016 – 26%) of the total proved plus probable value (discounted at 10%).

FAIR MARKET VALUE OF UNDEVELOPED LAND

Perpetual's independent third-party estimate of the fair market value of its undeveloped acreage by region for purposes of the NAV calculation is based on past Crown land sale activity, adjusted for tenure and other considerations. In West Central Alberta, no undeveloped land value was assigned where proved and/or probable undeveloped reserves have been booked.

Fair Market Value of Undeveloped Land


Net Acres

Value ($ millions)

$/Acre

Eastern and other

69,586

2.4

34.71

West Central

72,214

25.5

353.13

Oil Sands

188,640

18.8

99.58

Total

330,440

46.7

141.38

 

The fair market value of Perpetual's undeveloped land at year-end 2017, adjusted to remove the value of undeveloped lands with reserves assigned in West Central Alberta, is estimated by an external land consultant at $46.7 million, a decrease of 6% from $49.9 million relative to year-end 2016. The fair market value of undeveloped oil sands leases incorporates the absolute investment to date in the ongoing bitumen extraction pilot project at Panny and the undeveloped land value is also supported by recent land sale activity.

NET ASSET VALUE

The following NAV table shows what is normally referred to as a "produce-out" NAV calculation under which the Corporation's reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual's shares. The calculations below do not reflect the value of the Corporation's prospect inventory to the extent that the prospects are not recognized within the NI 51-101 compliant reserve assessment, except as they are valued through the estimate of the fair market value of undeveloped land.

Pre-tax NAV at December 31, 2017(1)










Discounted at

($ millions, except as noted)

Undiscounted

5%

8%

10%

15%

Total Proved plus Probable Reserves(2)

852.8

570.4

464.2

409.9

312.1

TOU share investment(3)

38.0

38.0

38.0

38.0

38.0

Fair market value of undeveloped land(5)

46.7

46.7

46.7

46.7

46.7

Bank debt, net of working capital(1)

(48.0)

(48.0)

(48.0)

(48.0)

(48.0)

TOU share margin loan(1)(3)(4)

(18.5)

(18.5)

(18.5)

(18.5)

(18.5)

Term loan(4)

(45.0)

(45.0)

(45.0)

(45.0)

(45.0)

Senior notes(4)

(32.5)

(32.5)

(32.5)

(32.5)

(32.5)

Hedge book(6)

(14.1)

(14.1)

(14.1)

(14.1)

(14.1)

NAV

779.4

497.0

390.8

336.5

238.7

Common shares outstanding (million)

59.3

59.3

59.3

59.3

59.3

NAV per share ($/share)

13.15

8.38

6.59

5.68

4.03

(1) 

Financial information is per Perpetual's 2017 preliminary unaudited consolidated financial statements.

(2)

Reserve values per McDaniel Report as at December 31, 2017.

(3)

TOU Share value based on 1.67 million shares at December 31, 2017 closing price ($22.78 per share).

(4)

Measured at principal amount.

(5)

Independent third-party estimate; excludes undeveloped land in West Central Alberta with reserves assigned.

(6)

Hedging adjustments, including shallow gas disposition obligations, as at December 31, 2017, relative to McDaniel's price forecast. Excludes market diversification contracts included in total proved plus probable reserves.

 

The above evaluation includes future capital expenditure expectations required to bring undeveloped reserves on production, as recognized by McDaniel's, that meet the criteria for booking under NI 51-101. Perpetual compiles annually a detailed internal estimate of the Corporation's total future decommissioning obligation based on net ownership interest in all wells, facilities and pipelines, including estimated costs to abandon the wells, facilities and pipelines and reclaim the sites, and the estimated timing of the costs to be incurred in future periods. Costs inclusive in McDaniel's reserve assessment align closely with the Company's estimate of total future decommissioning obligations, net of estimated salvage value of facilities and equipment, therefore no additional future decommissioning obligation adjustment is included. The fair market value of undeveloped land does not reflect the value of the Company's extensive prospect inventory which is anticipated to be converted into reserves and production over time through future capital investment.

FINDING AND DEVELOPMENT COSTS

Under NI 51-101, the methodology to be used to calculate finding and development ("F&D") costs includes incorporating changes in FDC required to bring the proved and probable undeveloped reserves to production. Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities, undeveloped reserve revisions and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production.

2017 F&D Costs(1)



($ millions except as noted)

Proved

Proved & Probable

F&D Costs, including FDC



Exploration and development capital expenditures(2)

$

73.0

$

73.0

Total change in FDC

$

8.0

$

(19.2)

Total F&D capital, including change in FDC

$

81.1

$

53.8

Reserve additions, including revisions – MMboe

11.1

8.7

F&D Costs, including FDC – $/boe

$

7.28

$

6.16




FD&A Costs, including FDC



Exploration and development capital expenditures(2)

$

73.0

$

73.0

Acquisitions, net of dispositions

$

(0.5)

$

(0.5)

Total change in FDC

$

8.0

$

(19.2)

Total FD&A capital, including change in FDC

$

80.6

$

53.3

Reserve additions, including net acquisitions – MMboe

11.3

8.9

FD&A Costs, including FDC – $/boe

$

7.14

$

5.98

(1)

Financial information is per Perpetual's 2017 preliminary unaudited consolidated financial statements.

(2)

Excludes corporate assets and expenditures on decommissioning obligations.

 

Comparison to prior year is not possible, as in 2016, F&D costs, including changes in FDC, could not be calculated as the change in FDC more than offset 2016 exploration and development spending. Similarly, Perpetual's FD&A costs could not be calculated in 2016 as the change in FDC and impact of dispositions more than offset exploration and development spending.

ADDITIONAL INFORMATION

Perpetual expects to release its 2017 annual audited financial statements and management's discussion and analysis ("MD&A") on or about February 23, 2018.

Oil and Gas Advisories

The reserves estimates contained in this news release represent our gross reserves as at December 31, 2017 and are defined under NI 51-101, as our interest before deduction of royalties and without including any of our royalty interests. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein.

All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs, and decommissioning obligations and are stated prior to provision for finance and general and administrative expenses. Future net revenues have been presented on a before tax basis. Estimated values of future net revenue disclosed herein do not represent fair market value.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

To provide a single unit-of-production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe), using the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

This news release contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio", "finding and development" costs or "F&D" costs, "F&D recycle ratio", "finding development and acquisition" costs or "FD&A" costs, "FD&A recycle ratio", "operating netbacks", "reserve life index" and "net asset value". This news release also refers to capital efficiency which is defined as a type of capital efficiency that measures the cost to add an incremental barrel of flowing production. Specifically, for the average production efficiencies of our plays, Perpetual uses the total actual/projected drill, complete and tie-in capital divided by the total of the well initial twelve-month production rate. Perpetual uses the term "prospect inventory" to refer to projects that do not meet the requirements to be classified as reserves either due to the timing of production, economic requirements or technical risk. These oil and gas metrics have been prepared by management and do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this news release to provide readers with additional measures to evaluate Perpetual's performance, however, such measures are not reliable indicators of Perpetual's future performance and future performance may not compare to Perpetual's performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders and investors with measures to compare Perpetual's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

F&D costs are calculated on a per boe basis by dividing the aggregate of the change in FDC from the prior year for the particular reserve category and the costs incurred on development and exploration activities in the year by the change in reserves from the prior year for the reserve category. FD&A costs are calculated on a per boe basis by dividing the aggregate of the change in FDC from the prior year for the particular reserve category and the costs incurred on development and exploration activities and property acquisitions (net of dispositions) in the year by the change in reserves from the year for the reserve category. Both F&D costs and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the F&D costs incurred in the financial year and changes during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year. F&D costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.

FD&A recycle ratio is calculated by dividing the operating netback for the period by the FD&A costs per boe for the particular reserve category.

Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, transportation and operating expenditures calculated on a per boe basis (see also "Non-GAAP Measures"). Reserve life index is calculated based on the amount for the relevant reserves category divided by the production forecast for the applicable year prepared by McDaniel.

Our estimated NAV is based on the estimated NPV10 of all future net revenue from our proved plus probable reserves, before tax, as estimated by McDaniel at year-end, with the estimated value of our undeveloped land, and less net debt. Common share values in our NAV per share metric are calculated using common shares outstanding, net of shares held in trust.

Unaudited financial information 

Certain financial and operating information included in this news release for the quarter and year-ended December 31, 2017, such as capital expenditures, FD&A costs, adjusted funds flow and net debt are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under "Forward-Looking Information". These estimated amounts may change upon the completion of audited financial statements for the year-ended December 31, 2017 and changes could be material.

The following abbreviations used in this news release have the meanings set forth below:

bbls    

barrels

Mbbls 

thousand barrels

boe 

barrels of oil equivalent

Mboe  

thousand barrels of oil equivalent

MMboe  

million barrels of oil equivalent

Mcf   

thousand cubic feet

MMcf 

million cubic feet

MMBtu 

million British Thermal Units

 

Forward-Looking Information 

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking information or statements under applicable securities laws. The forward looking information includes, without limitation, reserve estimates, potential for economic growth for shareholders; anticipated benefits of dispositions, including the shallow gas disposition dated October 1, 2016, anticipated amounts and allocation of capital spending; statements pertaining to adjusted  funds flow levels, future development and capital efficiencies; statements regarding estimated production and timing thereof; forecast average production; completions and development activities; infrastructure expansion and construction; estimated FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves; anticipated effect of commodity prices on reserves; estimated NAV; prospective oil and natural gas liquids production capability; projected realized natural gas prices and adjusted funds flow; estimated decommissioning obligations; anticipated effect of commodity prices on FDC and reserves; commodity prices and foreign exchange rates; and commodity price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release, which assumptions are based on management's analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this news release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's MD&A for the year-ended December 31, 2016 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.

Non-GAAP Measures

This news release contains the term "operating netbacks", "cash costs", and "net debt" which do not have standardized meanings prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other companies. Operating netbacks and cash costs are used by Perpetual to analyze operating performance. Perpetual believes these benchmarks are key measures of profitability and overall sustainability. These terms are commonly used in the oil and gas industry.

Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, transportation and operating expenditures calculated on a per boe basis. Cash costs are equal to the total of production and operating costs, transportation, royalties, general and administrative, and finance expenses. Net debt includes net working capital deficiency (surplus), revolving bank debt and the principal amount of the TOU share margin loan, Term Loan and Senior Notes reduced for the mark-to-market value of TOU shares held.

SOURCE Perpetual Energy Inc.

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