Altura Energy Inc. Announces Second Quarter 2017 Results and Provides Operational and Reserves Update

CALGARY, Aug. 10, 2017 /CNW/ - Altura Energy Inc. ("Altura", the "Company", or the "Corporation") (TSXV:ATU) is pleased to announce its financial and operating results for the second quarter of 2017 as well as an operational update and the results of a mid-year independent evaluation of the Company's oil and natural gas reserves.  The unaudited interim condensed consolidated financial statements and related management's discussion and analysis ("MD&A") will be available at www.sedar.com and www.alturaenergy.ca

OPERATIONAL AND FINANCIAL SUMMARY




Three months ended

Six months ended


June 30,
2017

March 31,

2017

June 30,

2016

June 30,

2017

June 30,

2016

OPERATING                                                                 






Average daily production







Light and medium oil (bbls/d)

652

539

259

595

294


Heavy oil (bbls/d)

346

309

12

327

12


Natural gas ­(mcf/d)

1,098

909

289

1,004

319


NGLs (bbls/d)

25

16

4

20

5


Total (boe/d)

1,205

1,015

323

1,110

364


Total boe/d per million shares – basic

11.1

9.3

3.0

10.2

3.3

Average realized prices







Light and medium oil ($/bbl)

50.69

53.52

44.60

51.96

35.47


Heavy oil ($/bbl)

45.36

46.23

35.43

45.77

28.08


Natural gas ($/mcf)

3.03

2.96

1.53

3.00

1.76


NGLs ($/bbl)

36.44

40.56

52.30

38.02

35.02


Total ($/boe)

43.93

45.76

39.08

44.76

31.60

NETBACK AND COST ($/boe)







Petroleum and natural gas sales

43.93

45.76

39.08

44.76

31.60


Royalties

(4.41)

(4.20)

(2.06)

(4.31)

(1.65)


Operating

(10.52)

(9.96)

(11.45)

(10.27)

(10.46)


Transportation

(2.71)

(2.26)

(2.88)

(2.51)

(2.84)

Operating netback(1)

26.29

29.34

22.69

27.67

16.65


General and administrative

(3.28)

(3.83)

(17.65)

(3.53)

(13.20)


Exploration expense

-

-

(1.01)

-

(0.45)


Interest and financing expense

(0.27)

(0.07)

(0.70)

(0.18)

(0.41)


Interest income

0.03

0.16

1.79

0.09

1.46

Corporate netback(1)

22.77

25.60

5.12

24.05

4.05

FINANCIAL ($000, except per share amounts)






Petroleum and natural gas sales

4,818

4,178

1,149

8,996

2,095

Funds from operations(1)

2,496

2,337

149

4,833

266


Per share – basic and diluted(1)

0.02

0.02

-

0.04

-

Cash flow from (used in) operating activities

2,269

2,794

28

5,063

(109)


Per share – basic and diluted

0.02

0.03

-

0.05

-

Income (loss)

594

13

(692)

607

(1,445)


Per share – basic and diluted

0.01

-

(0.01)

0.01

(0.01)

Capital expenditures, acquisitions and dispositions

3,078

8,952

2,294

12,030

2,498

Working capital surplus

1,156

2,436

20,011

1,156

20,011

Common shares outstanding (000)







End of period – basic

108,921

108,921

108,921

108,921

108,921


Weighted average for the period – basic

108,921

108,921

108,921

108,921

108,921


Weighted average for the period – diluted

109,082

109,289

108,921

109,191

108,921

(1)

Funds from operations, funds from operations per share, corporate netback, and operating netback, do not have standardized meanings prescribed by generally accepted accounting principles and therefore should not be considered in isolation.  These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used.  Where these measures are used they should be given careful consideration by the reader. Refer to the Non-GAAP Measures paragraph in the Advisories section of the MD&A.

 

SECOND QUARTER 2017 HIGHLIGHTS

  • Production volumes averaged 1,205 boe per day, a per share increase of 273 percent from the second quarter of 2016.
  • Corporate netback of $22.77 per boe, an increase of 345 percent from the second quarter of 2016.
  • Funds from operations were $2.5 million, up seven percent from the first quarter of 2017 and up $2.4 million from the second quarter of 2016.
  • Earnings of $594,000 compared to earnings of $13,000 in the first quarter of 2017 and a loss of $692,000 in the second quarter of 2016.
  • Net capital expenditures totaled $3.1 million. This included $2.2 million for completing five 100% working interest horizontal oil wells including: three Sparky oil wells at Eyehill; one Sparky oil well at Macklin; and one Rex oil well at Killam. Equipping the new wells and facility costs related to the multi-well battery upgrade in the Eyehill area totaled $1.0 million. Additionally, Altura disposed of undeveloped land in the Provost area for proceeds of $750,000 (the "Provost Disposition").
  • Ended the quarter with a Liability Management Rating ("LMR") of 8.0 with the Alberta Energy Regulator.
  • The credit facility was increased to $7.5 million from $4.0 million based on the year-end 2016 reserve report.
  • Ended the quarter with a $1.2 million working capital surplus and no debt.

OPERATIONAL UPDATE

Leduc-Woodbend

In Leduc-Woodbend, the new 102/12-15-049-26W4 ("12-15") horizontal well that was drilled in the first quarter of 2017 commenced production at the end of March and continues to deliver strong results with an average IP(90) rate of 198 boe per day (81% oil).  For the month of July, the 12-15 well produced 158 boe per day (70% oil) with a 55% water cut.  Altura's initial Leduc-Woodbend horizontal well, 100/13-15-048-26W4, which was initially placed on production in November 2016, produced 70 boe per day (80% oil) in July with a 75% water cut. 

Altura plans to build upon this success by re-allocating $5.3 million of the Company's second half 2017 drilling capital budget to drill two extended reach horizontal ("ERH") wells at Leduc-Woodbend in the third quarter.  The ERH wells will have a horizontal length of 2,000 metres and a total of 44 frac stages which represents a 45 percent increase in the horizontal length and stage count from the previous one-mile wells drilled in the area.  The Corporation anticipates these ERH wells will result in a positive impact to the already strong economics of Altura's development plan for the area.

In the second half of 2017, Altura is also accelerating $2.2 million of infrastructure projects in the Leduc-Woodbend area.  This includes capital investments to build, pipeline connect and operate a gas gathering, emulsion and produced water pipeline and water disposal facility.  Altura will also commence equipment purchases and initial construction of an expandable multi-well battery having an initial capacity of 3,000 barrels of oil per day.  The pipeline will allow Altura to conserve gas and reduce produced water trucking and disposal costs associated with pool development and production.  Altura has acquired two water disposal wells and pipelines that will facilitate this initiative.  Altura estimates the new water handling and disposal facilities will reduce corporate operating costs by approximately $0.80 per boe commencing in the fourth quarter of 2017.  As previously disclosed, the Corporation has acquired eight multi-well drilling pads to maximize efficiencies of initial pool development.

Eyehill

In Eyehill, the Company successfully completed and equipped the three Sparky horizontal wells that were drilled in the first quarter of 2017.  After 95 days of production, the wells continue to produce as expected and have added a total of 300 boe per day to our base production for the area.

In addition, Altura converted the 100/03-11-037-03W4 one-mile horizontal well to a water injector and commenced the waterflood pilot in August.  This is expected to improve the rates of offsetting producing wells and further reduce operating costs related to water trucking and disposal.      

Macklin

In the first quarter of 2017 Altura drilled the first horizontal well in the Macklin Sparky oil pool.  The well was successfully completed and equipped in early April and commenced production at the end of April.  Initial results from this well are very encouraging with an IP(60) rate of 73 barrels of oil per day.  After 80 days of production, the well is producing at 75 barrels of oil per day.  The solution gas of 26 mcf per day (4 boe per day) is used at the lease for fuel gas and is not sold. 

Altura is planning to drill additional wells from this initial multi-well pad in 2018.

Killam

In Killam, the 100/15-15-044-13W4 ("15-15") horizontal well that was drilled in the first quarter of 2017 was successfully completed and equipped in the second quarter of 2017.  The 15-15 horizontal well was the first in this Rex oil pool to be completed with a multi-stage hydraulic fracture stimulation.  It was placed on production in April 2017 and produced 55 boe per day (78% oil) from July 1 to July 25, 2017, at which time it was shut-in for temporary third-party pipeline maintenance and is expected to resume production mid-August.  It is believed that approximately 30% of the horizontal lateral was impacted by a localized coal seam in the Rex which has resulted in reduced production rates from the well.  Altura is evaluating the impact, if any, on future drilling opportunities in this local region of the pool. 

OUTLOOK

Altura has accumulated a large oil-weighted drilling inventory with exposure to several different plays and continues to pursue conventional crude oil plays in the Western Canadian Sedimentary Basin with a focus in central Alberta targeting the shallow, multi-zone, oil-weighted section of the Upper Mannville Group.  This area is expected to generate strong cash netbacks with competitive drilling and completion costs for these shallow targets, thereby delivering attractive economics in the context of the current commodity price environment.  

Through the remainder of 2017, Altura plans to drill two extended reach horizontal wells at Leduc-Woodbend and to build, pipeline connect and operate a gas gathering, emulsion and produced water pipeline and water disposal facility to reduce operating costs associated with pool development and production.  Additionally, the Company plans to commence equipment purchases and initial construction of a multi-well battery at Leduc-Woodbend that is expected to be commissioned in the first half of 2018. 

Altura has accumulated a large land position totaling 56 net sections in the Leduc-Woodbend area with encouraging early results from the two horizontal wells drilled to date.  As a result, the board of directors of the Company has approved a $3.0 million increase to the capital development budget for 2017 with all of the increase directed towards advancing the larger scale opportunity at Leduc-Woodbend.  The capital development budget is now expected to total $20.0 million with $14.6 million to drill, complete, equip and tie-in a total of eight 100% working interest wells.  Approximately 60% of the total budget will be invested in the Leduc-Woodbend area.

Assuming $14.6 million of well-related capital, the planned eight net well drilling program is forecast to add approximately 750 boe per day by December 2017, which delivers a capital efficiency of approximately $19,500/boe per day. The incremental production is expected to offset forecast base declines and grow overall production to exit 2017 at a rate of approximately 1,350 boe per day which represents a 37% increase over fourth quarter 2016 of 988 boe per day. 

RESERVES

Due to the Company's successful first half of 2017 drilling program, Altura requested the independent reserve evaluator, McDaniel & Associates Consultants Ltd. ("McDaniel"), to prepare a mid-year reserve report (the "McDaniel Report") as of June 30, 2017. 

Mid-Year 2017 Reserves Highlights

  • Proved developed producing ("PDP") reserves increased by 33 percent from 1,099 mboe at year-end 2016 to 1,464 mboe. Total proved ("1P") reserves increased by 43 percent from 1,821 mboe at year-end 2016 to 2,604 mboe. Total proved and probable ("2P") reserves increased by 43 percent from 3,195 mboe at year-end 2016 to 4,568 mboe.
  • Leduc-Woodbend PDP reserves increased by 123 percent to 157 mboe, 1P reserves increased by 800 percent to 631 mboe, and 2P reserves increased by 522 percent to 1,460 mboe, all from respective year-end 2016 reserves.
  • First half of 2017 finding, development and acquisitions ("FD&A") costs1 were $21.26 per boe for PDP, $22.33 per boe for 1P and $17.06 per boe for 2P reserves, including the changes in future development costs ("FDC"). This includes $2.6 million (21% of total capital expenditures) pertaining to costs not directly related to reserve additions, including: land costs, geologic and geophysical costs, facilities costs, the Provost Disposition, and capitalized G&A.
  • Recycle ratio1 of 1.3 times for PDP, 1.2 times for 1P, and 1.6 times for 2P reserves based on June 30, 2017 FD&A costs and Altura's first half of 2017 operating netback1 of $27.67 per boe.
  • Replaced1 282 percent of first half of 2017 production with new PDP reserves, 490 percent of first half of 2017 production with new 1P reserves and 784 percent of first half of 2017 production with new 2P reserves based on first half of 2017 production of 201 mboe.

June 30, 2017 Independent Reserves Evaluation

The McDaniel Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 ("NI 51-101").  The reserve evaluation was based on McDaniel's forecast pricing and foreign exchange rates at July 1, 2017. The Reserves Committee of the Board and the Board of Directors of Altura have reviewed and approved the evaluation prepared by McDaniel.

Unless noted otherwise, reserves included herein are stated on a company gross basis, which is the Company's working interest before deduction of government royalties and excluding any other additional royalty interests. This news release contains several cautionary statements under the heading "Reader Advisory" and throughout the release. In addition to the information contained in this news release, more detailed reserves information will be included in an updated Statement of Reserves and Resource Data and Other Oil and Gas Information filed on SEDAR by August 31, 2017.

_________________________

1

"Operating netback", "Finding, development & acquisitions costs" or "FD&A costs", "Recycle ratio", and "Reserve replacement", do not have standardized meanings. See "Non-GAAP Measures" and "Oil and Gas Metrics" contained in this news release.

 

Company Gross Reserves as of June 30, 2017

The following table summarizes the Company's gross reserve volumes at June 30, 2017 utilizing McDaniel's forecast pricing and cost estimates outlined further below in this press release.









Company Gross Reserves(1)(2)

Category


Light and
Medium
Oil
(Mbbl)

Heavy Oil
(Mbbl)

Conventional
Natural Gas
(Mmcf)

Natural
Gas
Liquids
(Mbbl)

June 30,
2017 Oil
Equivalent
(Mboe)

December
31, 2016 Oil
Equivalent
(Mboe)

Percent
Change

Proved










Developed Producing


893.0

280.4

1,609.0

22.7

1,464.2

1,099.2

33%


Non-producing


32.0

-

27.2

0.5

37.0

-

-


Undeveloped


303.0

622.6

962.7

16.6

1,102.6

722.2

53%

Total Proved(3)


1,228.0

903.0

2,598.9

39.7

2,603.8

1,821.4

43%

Total Probable


642.8

1,037.8

1,498.8

33.8

1,964.3

1,373.8

43%

Total Proved & Probable(3)


1,870.8

1,940.8

4,097.6

73.5

4,568.1

3,195.2

43%

(1)

Gross reserves are Company working interest reserves before royalty deductions.

(2)

Based on McDaniel's July 1, 2017 forecast prices.

(3)

Numbers may not add due to rounding.

 

Reconciliation of Company Gross Reserves from December 31, 2016 to June 30, 2017(1)(2)








Total Proved Oil
Equivalent (mboe)

Total Probable Oil
Equivalent (mboe)

Total Proved &
Probable Oil
Equivalent (mboe)

December 31, 2016


1,821.4

1,373.8

3,195.2

Extensions & Improved Recovery


748.0

772.7

1,520.7

Technical Revisions


235.4

(182.3)

53.1

Discoveries


-

-

-

Acquisitions & Dispositions


-

-

-

Economic Factors


-

-

-

Production


(201.0)

-

(201.0)

June 30, 2017


2,603.8

1,964.3

4,568.1

(1)

Gross reserves are Company working interest reserves before royalty deductions.

(2)

Numbers may not add due to rounding.

 

Technical revisions for the 1P reserve category is positive due to the conversion of probable reserves to proved reserves and well performance exceeding the previous year's forecast.  Technical revisions for the 2P reserve category is positive due to well performance exceeding the previous year's forecast.  

Future Development Costs ("FDC") and Well Schedule

The following is a summary of the estimated FDC and number of wells required to bring 1P and 2P undeveloped reserves on production.









Total Proved
FDC(1)(2)
($000)

Total Proved
Wells
Gross (Net)

Total Proved &
Probable FDC(1)(2)
($000)

Total Proved &
Probable
Wells
Gross (Net)







2017


2,650

1 (1.0)

5,300

2 (2.0)

2018


7,874

5 (5.0)

11,705

7 (7.0)

2019


9,101

8 (7.0)

14,644

14 (11.7)

Total Undiscounted


19,625

14 (13.0)

31,649

23 (20.7)

Total Discounted 10%


17,207


27,856


(1)

Numbers may not add due to rounding.

(2)

FDC as per the McDaniel Report and based on McDaniel's July 1, 2017 forecast prices.

 

The forecasted future net operating income for the next two and a half years from the McDaniel Report based on the July 1, 2017 forecasted pricing is estimated to be $32.5 million for 1P reserves and $46.6 million for 2P reserves, which is sufficient to fund Altura's FDC for the next three years.

Summary of Before Tax Net Present Value ("NPV") of Future Net Revenue as of June 30, 2017

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs are based on McDaniel's forecast pricing and foreign exchange rates at July 1, 2017 as outlined in the price forecast table further below in this press release.  The NPVs include a deduction for estimated future well abandonment and reclamation but do not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimate represents the fair market value of the reserves.









Before Tax Net Present Value ($000) (1)(2)(3)



Discount Rate

Category


Undiscounted

5%

10%

15%

20%

Proved








Developed Producing


38,685

33,938

30,141

27,127

24,716


Non-producing


1,414

972

704

532

416


Undeveloped


13,939

9,860

6,827

4,593

2,938

Total Proved


54,038

44,770

37,671

32,252

28,069

Total Probable


55,168

37,988

27,523

20,822

16,302

Total Proved & Probable


109,206

82,758

65,194

53,074

44,372

(1)

Based on McDaniel's July 1, 2017 forecast prices.

(2)

Includes abandonment and reclamation costs.

(3)

Numbers may not add due to rounding.

 

Performance Metrics(1)
Altura's first half of 2017 FD&A costs were $21.26 per boe for PDP reserves, $22.33 per boe for 1P reserves and $17.06 per boe for 2P reserves, including the change in FDC.  The following table highlights Altura's FD&A, recycle ratio, reserve replacement and reserve life index as of June 30, 2017. 






June 30, 2017

Total H1 2017 capital expenditures, acquisitions and dispositions ($000)


12,030

Change in FDC – Total Proved ($000)


9,928

Change in FDC – Total Proved & Probable ($000)


14,827

Q2 2017 production (boe/d)


1,205

H1 2017 Operating netback ($/boe)(2)


27.67




Proved Developed Producing



FD&A costs ($/boe)(2)


21.26

Recycle ratio(2)


1.3

Reserve replacement(2)


282%

Reserve life index ("RLI") (years)(2)


3.3




Total Proved



FD&A costs ($/boe)(2)


22.33

Recycle ratio(2)


1.2

Reserve replacement(2)


490%

RLI (years)(2)


5.9




Total Proved & Probable



FD&A costs ($/boe)(2)


17.06

Recycle ratio(2)


1.6

Reserve replacement(2)


784%

RLI (years)(2)


10.4

(1)

Financial and production information is per the Company's unaudited interim condensed financial statements for the three and six months ended June 30, 2017. 

(2)

"Operating netback", "Finding, development & acquisitions costs" or "FD&A costs", "Recycle ratio", "Reserve replacement", "Reserve life index" or "RLI" do not have standardized meanings.  See "Non-GAAP Measures" and "Oil and Gas Metrics" contained in this news release.

 

Price Forecast
The reserve evaluation was based on McDaniel's forecast pricing and foreign exchange rates at July 1, 2017 as outlined below.





















WTI
Crude Oil
($US/bbl)


Western Canadian Select
Crude Oil
($CAD/bbl) 


Alberta AECO
Gas
($CAD/mmbtu)


 

Foreign Exchange
($US/$CAD)

2017 (6 mos)


50.00


47.60


2.85


0.760


2018


56.10


54.60


2.85


0.775


2019


59.80


57.90


3.05


0.800


2020


63.70


61.80


3.25


0.800


2021


70.40


66.40


3.60


0.825


2022


74.50


70.40


3.90


0.825


2023


78.80


72.30


4.00


0.850


2024


80.40


73.80


4.05


0.850


2025


82.00


75.30


4.15


0.850


2026


83.70


76.80


4.25


0.850


2027


85.30


78.30


4.30


0.850


2028


87.00


79.90


4.40


0.850


2029


88.80


81.50


4.50


0.850


2030


90.60


83.10


4.60


0.850


2031


92.40


84.80


4.70


0.850


thereafter


+2.0%/yr


+2.0%/yr


+2.0%/yr


0.850

 

ABOUT ALTURA ENERGY INC.

Altura Energy Inc. is a public oil and gas Company active in the exploration and development of oil and natural gas in east central Alberta.

READER ADVISORIES

Forwardlooking Information and Statements

This press release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "budget", "forecast", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements.  In particular, but without limiting the foregoing, this press release contains forward-looking information and statements pertaining to the 2017 capital expenditure budget, plans concerning the length and number of stages in ERH wells, plans concerning future water disposal facilities and battery at Leduc-Woodbend, expected date of resuming production at Killam, planned improved production rates at Eyehill, timing of planned gas gathering, emulsion and produced water disposal facilities at Leduc-Woodbend,  expected cost reductions at Eyehill and Leduc-Woodbend and planned 2018 drilling in Macklin.  Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking information and statements contained in this press release reflect several material factors and expectations and assumptions of Altura including, without limitation:

  • the continued performance of Altura's oil and gas properties in a manner consistent with its past experiences
  • that Altura will continue to conduct its operations in a manner consistent with past operations;
  • the general continuance of current industry conditions;
  • the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes;
  • the accuracy of the estimates of Altura's reserves and resource volumes;
  • certain commodity price and other cost assumptions;
  • the continued availability of oilfield services; and
  • the continued availability of adequate debt and equity financing and cash flow from operations to fund its planned expenditures.

Altura believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. To the extent that any forward-looking information contained herein may be considered future oriented financial information or a financial outlook, such information has been included to provide readers with an understanding of management's assumptions used for budgeted and developing future plans and readers are cautioned that the information may not be appropriate for other purposes.

The forward-looking information and statements included in this press release are not guarantees of future performance and should not be unduly relied upon.  Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation:

  • changes in commodity prices;
  • changes in the demand for or supply of Altura's products;
  • unanticipated operating results or production declines;
  • changes in tax or environmental laws, royalty rates or other regulatory matters;
  • changes in development plans of Altura or by third party operators of Altura's properties,
  • increased debt levels or debt service requirements;
  • inaccurate estimation of Altura's oil and gas reserve and resource volumes;
  • limited, unfavorable or a lack of access to capital markets;
  • increased costs;
  • a lack of adequate insurance coverage;
  • the impact of competitors; and
  • certain other risks detailed from time to time in Altura's public documents.

The forward-looking information and statements contained in this press release speak only as of the date of this press release, and Altura does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

NonGAAP Measures

This press release contains references to measures used in the oil and natural gas industry such as "funds from operations", "corporate netback", "funds from operations per share", and "operating netback".  These measures do not have standardized meanings prescribed by generally accepted accounting principles ("GAAP") and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used.  Where these measures are used, they should be given careful consideration by the reader.  These measures have been described and presented in the press release in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. 

Funds from operations should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with GAAP, as an indicator of Altura's performance or liquidity.  Funds from operations is used by Altura to evaluate operating results and the Company's ability to generate cash flow to fund capital expenditures and repay indebtedness.  Funds from operations denotes cash flow from operating activities as it appears on the Company's statement of cash flows before decommissioning expenditures, if any, transaction costs and changes in non‐cash operating working capital.  Funds from operations is also derived from income (loss) plus transaction costs and non‐cash items including depletion, depreciation and amortization expense, share‐based compensation expense, impairment, the gain (loss) on investments, gains (losses) on disposition of assets and accretion expense.  Funds from operations per share is calculated as funds from operations divided by the weighted average number of basic and diluted common shares outstanding.  Operating netback denotes total sales less royalty expenses, and operating and transportation costs calculated on a per boe basis.  Corporate netback denotes operating netback less general and administrative, interest and financing expense, exploration expense plus interest income on a per boe basis.  

Oil and Gas Advisories

Reserves

All reserve references in this press release are "company share reserves". Company share reserves are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests of the Company.

It should not be assumed that the present value of estimated future net revenue 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 reserve estimates of Altura's crude oil, natural gas liquids 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 natural gas liquids 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 abandonment and reclamation costs and are stated prior to provision for interest 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.

Barrels of Oil Equivalent

The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation.  Per boe amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 mcf) of natural gas to one barrel (1 bbl) of crude oil.  The boe conversion ratio of 6 mcf to 1 bbl 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 equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by Altura as set out below.  These metrics are "finding, development and acquisition costs", "recycle ratio", "reserve replacement", and "reserve life index".  These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies.  As such, they should not be used to make comparisons.  Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Altura's performance over time, however, such measures are not reliable indicators of Altura's future performance and future performance may not compare to the performance in previous periods.

  • "Finding, development and acquisition costs" or "FD&A costs" are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the period inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.
    FD&A costs take into account reserves revisions and capital revisions during the period. The aggregate of the costs incurred in the financial period and changes during that period in estimated FDC may not reflect total F&D costs related to reserves additions for that period. FD&A costs have been presented in this news release because acquisitions and dispositions can have a significant impact on Altura's ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure. Management uses FD&A as measures of its ability to execute its capital programs (and success in doing so) and of its asset quality.

  • "Recycle ratio" or is calculated by dividing the operating netback (in dollars per boe) by the FD&A costs (in dollars per boe) for the period. Altura uses recycle ratio as an indicator of profitability of its oil and gas activities.

  • "Reserve replacement" is calculated by dividing the period change in reserves before production (in boe) in the referenced category by Altura's production (in boe) for that period. Management uses this measure to determine the relative change of its reserves base over a period of time.

  • "Reserve life index" or "RLI" is calculated by dividing the reserves (in boe) in the referenced category by the Q2 2017 production estimate (in boe). Management uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.

Initial Production Rates

Any references in this press release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Oil and gas formations are inherently unpredictable, particularly in the early stage of their development. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE Altura Energy Inc.

For further information: Altura Energy Inc., 200, 640 - 5th Avenue SW, Calgary, Alberta T2P 3G4, Telephone (403) 984-5197, www.alturaenergy.ca; David Burghardt, President and Chief Executive Officer, Direct (403) 984-5195; Tavis Carlson, Vice President, Finance and Chief Financial Officer, Direct (403) 984-5196


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