InPlay Oil Corp. Announces 2016 Year End Reserves and an Operations Update

CALGARY, AB–(Marketwired – March 14, 2017) – InPlay Oil Corp. (“InPlay” or the “Company“) (TSX: IPO) is pleased to present the results of the Company’s independent reserves evaluation (the “Sproule Report“) prepared by Sproule Associates Ltd. (“Sproule“) effective as of December 31, 2016 and an operations update.

In November 2016, InPlay completed a series of transformational transactions including the go-public reverse takeover (the “Arrangement“) of Anderson Energy Inc., a “bought deal” equity financing for aggregate gross proceeds of $70.3 million and a significant asset acquisition in its core Pembina area (the “Asset Acquisition“).

InPlay successfully executed its strategy in 2016 of assembling a light oil company with premier assets that can provide shareholders with top tier organic growth amongst light oil weighted peers. The Company’s strategy was to build a sustainable light oil resource base backed by solid, predictable reserves with a strong balance sheet and supported by an inventory of high return quick payout drilling locations.

The InPlay team’s efforts to date have resulted in proved developed producing, total proved and total proved plus probable reserve life indices of 5.7, 13.0 and 19.3 years respectively, with an estimated base 2017 proved developed producing decline of 21%. The Company is anticipating >20% per share organic production growth (>25% on a debt adjusted basis) forecasted for the month of December 2017 over December 2016 and debt to cash flow of 1.0 times or less. Also, we have put together a large inventory of drilling locations with payouts estimated at less than one year.

2016 Reserves Highlights:

  • Proved Developed Producing (“PDP“) reserves
    • Increased by 135% from 3,106.8 mboe to 7,304.0 mboe (65% oil & liquids).
    • Replaced production by 691%.
    • FD&A costs including the change in future development capital (“FDC”) of $18.12 per boe resulting in a recycle ratio of 1.3 times.
    • Reserve life index of 5.7 years, an increase of 29%.
  • Total Proved (“TP“) reserves
    • Increased by 187% from 5,776.8 mboe to 16,578.5 mboe (67% oil & liquids).
    • Replaced production by 1,621%.
    • FD&A costs including the change in FDC of $14.13 per boe resulting in a recycle ratio of 1.6 times.
    • Reserve life index of 13.0 years, an increase of 58%.
  • Proved plus Probable (“P+P“) reserves
    • Increased by 180% from 8,739.4 mboe to 24,485.7 mboe (69% oil).
    • Replaced production by 2,318%.
    • FD&A costs including the change in FDC of $11.54 per boe resulting in a recycle ratio of 2.0 times.
    • Reserve life index of 19.3 years, an increase of 55%.
  • Using the independent reserves evaluation effective December 31, 2016, the net present value of future net revenues discounted at 10% (“PV10”) before taxes of our P+P reserves, inclusive of our internally estimated undeveloped land value and seismic value of $17.5 million, a fair market value liability of $1.5 million on our commodity derivative contracts and net of estimated net debt at year end of $35.0 million equates to an estimated net asset value of $4.78 per common share.

Operations Update:

Since the completion of the Arrangement and related transactions on November 7, 2016, the Company has drilled 10 (8.0 net) light oil Cardium horizontal wells. The drilling program was completed on February 10, 2017, of which 2 (1.9 net) wells came on production in late 2016 and 3 (3.0 net) wells came on production in the middle of February, 2017. There are currently 5 (3.1 net) wells remaining to be completed, equipped and tied in for production. We currently expect these wells will be completed and brought on production through March and April, and even with delays in completions due to high industry activity, we continue to be on target with our production guidance of 4,000 – 4,200 boed average for 2017 and 4,300 – 4,500 boed 2017 exit.

Early results from our new wells, which includes 3 net wells having only one month of production and still in the clean-up stage, are exceeding internal forecasts. These new wells coupled with the low decline asset base has current production, based on field estimates, at approximately 4,100 boed (65% light oil and liquids). The Company anticipates drilling an additional 8 net Cardium horizontal wells prior to yearend, with 7 of the wells slated for the second half of 2017.

2016 Independent Reserves Evaluation:

The following summarizes certain information contained in the Sproule Report. The Sproule Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook“) and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101“). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF“) which will be filed on SEDAR by the end of March 2017.

Corporate Reserves Information:

December 31, 2016

Reserves Category

  Crude Oil
& NGLs(1)
Natural Gas


Proved developed producing   4,749.4   15,328   7,304.0   113,639    
Proved developed non-producing   576.4   1,303   793.5   13,395   2,753  
Proved undeveloped   5,820.3   15,964   8,841   74,261   126,310   70.3
Total proved   11,146.0   32,595   16,578.5   201,295   129,064   70.3
Probable developed producing   1,342.2   4,422   2,079.2   28,192    
Probable developed non-producing   152.1   342   209.0   3,528    
Probable undeveloped   4,310.0   7,854   5,619.0   84,297   49,349   27.7
Total probable   5,804.3   12,617   7,907.2   116,016   49,349   27.7
Total proved plus probable   16,950.3   45,212   24,485.7   317,311   178,413   98.0


  1. “Oil & NGL” reserves include all light crude oil & medium oil volumes, and natural gas liquids volumes.
  2. Reserves have been presented on gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.
  3. Based on Sproule’s December 31, 2016, escalated price forecast.
  4. It should not be assumed that the net present value of estimated future net revenue (“NPV”) 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 InPlay’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.
  5. All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
  6. Totals may not add due to rounding.

Net Asset Value:

December 31, 2016            
    BTAX NPV 5%     BTAX NPV 10%  
    ($000’s)     $/share(5)     ($000’s)     $/share(5)  
P+P NPV(1)(2)   416,602     6.68     317,311     5.09  
Undeveloped acreage(3) & seismic   17,520     0.28     17,520     0.28  
Net debt(4)   (35,000 )   (0.56 )   (35,000 )   (0.56 )
Fair Market Value of commodity derivative contracts   (1,548 )   (0.03 )   (1,548 )   (0.03 )
Net Asset Value (fully-diluted)   397,574     6.37     298,283     4.78  


  1. Evaluated by Sproule as at December 31, 2016. The estimated net present value of future net revenue (“NPV”) does not represent fair market value of the reserves.
  2. Based on Sproule’s forecast prices and costs as of December 31, 2016.
  3. Internally evaluated with an average value of $174 per acre for 81,964 undeveloped net acres and the estimated value of the sizeable seismic database recently acquired.
  4. Estimated net debt as at December 31, 2016, including working capital deficit (unaudited).
  5. Based upon 62,396,169 total common shares outstanding as at Dec 31, 2016. There are no dilutive instruments outstanding as of Dec 31, 2016.

Future Development Costs:

The following is a summary of the estimated FDC required to bring InPlay’s undeveloped reserves on production.

Future Development Capital Costs (amounts in $000,000’s) (1)
    Total Proved   Total Proved +
2017   23.9   32.7
2018   51.5   58.4
2019   53.6   71.4
2020   0   15.9
Total undiscounted FDC   129.0   178.4
Total discounted FDC at 10% per year   110.2   149.9


  1. FDC as per Sproule Report based on Sproule forecast pricing as at December 31, 2016

Performance Measures(1):

Average crude oil price WTI US$/bbl   43.32
E&D Capital ($000’s)(2)   10,251
Production boed – Full Year 2016   1,940
Production boed – Dec 2016   3,484
Operating netback $/boe – Full Year 2016   17.57
Operating netback $/boe – Dec 2016   22.96
Proved Developed Producing    
  Total Reserves mboe   7,304
  Reserves additions mboe   4,907.2
  FD&A $/boe(2)   18.12
  Recycle Ratio(3)   1.3
  Reserves Replacement(4)   691%
  RLI (years)(5   5.7
Total Proved    
  Total Reserves mboe   16,579
  Reserves additions mboe   11,511.7
  Change in FDC ($000’s)   73,791
  FD&A $/boe(2)   14.13
  Recycle Ratio(3)   1.6
  Reserves Replacement(4)   1,621%
  RLI (years)(5)   13.0
Proved Plus Probable    
  Total Reserves mboe   24,486
  Reserves additions mboe   16,456.3
  Change in FDC ($000’s)   101,417
  FD&A $/boe(2)   11.54
  Recycle Ratio(3)   2.00
  Reserves Replacement(4)   2,318%
  RLI (years)(5)   19.3


  1. Financial and production information represent Management estimates per the Company’s 2016 preliminary unaudited financial statements and is therefore subject to audit. Readers are advised that these results may be subject to change.
  2. Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) expenditures and “Acquisition Capital” for the Asset Acquisition and the Arrangement plus the change in Future Development Capital (“FDC”) for that period. This total of capital expenditures, including the change in the FDC, is then divided by the change in reserves for that period incorporating all revisions and production for that same period. For example: 2016 Total Proved = ($88.9 mm + $73.7 mm) / (16,579 mboe – 5,776 mboe + 710 mboe) = $14.13 per boe. E&D capital and the FD&A calculation excludes capitalized G&A expenditures.
  3. Recycle Ratio is calculated by dividing the month of December’s operating netback per boe by the FD&A costs for that period. For example: 2016 Total Proved = ($22.96/$14.13) = 1.63. The month of December’s netback is used rather than the full year netback as it is the most representative of the Company going forward and it reflects the first full month of operating results following the completion of the Arrangement and Asset Acquisition. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves.
  4. The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2016 Total Proved = (16,578.5 mboe – 5,776.8 mboe + 710 mboe) / 710 mboe = 1,621%.
  5. RLI is calculated by dividing the reserves in each category by the month of December’s average production. For example 2016 Total Proven = (16,578.5 mboe) / (3,484 boed * 366) = 13.0 years. The month of December’s average production is used rather than the full year production as it reflects a full month of operating results following the completion of the Arrangement and Asset Acquisition.

Pricing Assumptions:

The following tables set forth the benchmark reference prices, as at December 31, 2016, reflected in the Sproule Report. These price assumptions were provided to InPlay by Sproule and were Sproule’s then current forecast at the date of the Sproule Report.


as of December 31, 2016

Year   WTI
LSB 35°

Edmonton Propane
  Operating Cost
Inflation Rates

Inflation Rates
2017   55.00   65.58   64.58   3.44   22.74   47.60   67.95   0.0%   0.0%   0.780
2018   65.00   74.51   73.51   3.27   28.04   55.49   75.61   2.0%   2.0%   0.820
2019   70.00   78.24   77.24   3.22   30.64   57.65   78.82   2.0%   2.0%   0.850
2020   71.40   80.64   79.64   3.91   32.27   58.80   80.47   2.0%   2.0%   0.850
2021   72.83   82.25   81.25   4.00   33.95   59.98   82.15   2.0%   2.0%   0.850
2022   74.28   83.90   82.90   4.10   35.68   61.18   83.86   2.0%   2.0%   0.850
    Thereafter Escalation rate of 2.0%


  1. This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
  2. The exchange rate used to generate the benchmark reference prices in this table.
  3. As at December 31, 2016.


We are pleased with the results that we have seen from the assets acquired in the fourth quarter of 2016 both on the base production and the drilling results to date and we look forward to further optimization and development of these assets. InPlay is well positioned financially to support our 2017 developmental capital program. Low debt levels, high netbacks and a solid suite of commodity hedges leaves us well positioned to continue to develop our asset base in the current volatile commodity price environment. Efforts will continue to be focused on operational excellence in order to execute a solid development plan over the entire asset base in a manner that should result in meaningful per share growth to InPlay shareholders.

Additional corporate information can be found on our website at or on

Cautionary Statements

Unaudited financial information

Certain financial and operating information included in this press release for the quarter and year ended December 31, 2016, including FD&A costs, E&D capital, netbacks 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 set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2016 and changes could be material.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information

Our oil and gas reserves statement for the year ended December 31, 2016, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading “Forward-Looking Information and Statements”.

This press release contains metrics commonly used in the oil and natural gas industry, such as “recycle ratio”, “finding, development and acquisition costs”, “operating netbacks”, “reserves replacement” and “reserve life index”. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.

The term “debt adjusted basis” is calculated assuming the net debt balances at the end of a period were to be extinguished with a share issuance assuming an average $2.00 share price.

Finding, development and acquisition costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated future development costs may not reflect total finding and development costs related to reserves additions for that year. Finding, development and acquisition costs have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Exploration & development capital means the aggregate exploration and development costs incurred in the financial year on exploration and on reserves that are categorized as development. Exploration & development capital excludes capitalized administration costs. Acquisition capital amounts to the total amount of cash and share consideration net of any working capital balances assumed with an acquisition on closing.

Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare InPlay’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 press release, should not be relied upon for investment or other purposes.

Forward-looking information and statements

This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves, the volumes and estimated value of InPlay’s oil and gas reserves; the life of InPlay’s reserves; the volume and product mix of InPlay’s oil and gas production; estimated payout time on new wells, future oil and natural gas prices and InPlay’s commodity risk management program; future results from operations and operating metrics including potential rates of return, per share growth and debt to cash flow forecasts, future development, exploration, acquisition and disposition activities (including drilling and completion plans and associated timing and costs), and InPlay’s 2017 capital budget and production guidance including 2017 average and year end exit rates.

The recovery and reserve estimates of InPlay’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that InPlay will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past operations; the quality of the reservoirs in which InPlay operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of InPlay’s reserve volumes; certain commodity price and other cost assumptions; continued availability of equity financing and cash flow to fund InPlay’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which InPlay operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of InPlay to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which InPlay has an interest in to operate the field in a safe, efficient and effective manner; the ability of InPlay to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of InPlay to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which InPlay operates; and the ability of InPlay to successfully market its oil and natural gas products.

The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statement, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer 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 InPlay’s products, the early stage of development of some of the evaluated areas and zones; the potential for variation in the quality of the formations; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of InPlay or by third party operators of InPlay’s properties, increased debt levels or debt service requirements; inaccurate estimation of InPlay’s oil and gas reserve volumes; limited, unfavourable 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 InPlay’s public disclosure documents, (including, without limitation, those risks identified in this news release and InPlay’s Annual Information Form).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and InPlay does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

BOE equivalent

Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 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 ration based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 ratio may be misleading as an indication of value.

For further information please contact:

Doug Bartole
President and Chief Executive Officer
InPlay Oil Corp.
Telephone: (587) 955-0632

Darren Dittmer
Chief Financial Officer
InPlay Oil Corp.
Telephone: (587) 955-0634