CALGARY, Alberta, March 20, 2019 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and operating results for the three and twelve months ended December 31, 2018, and the results of its independent oil and gas reserves evaluation effective December 31, 2018 (the “Sproule Report”) prepared by Sproule Associates Limited (“Sproule”). InPlay’s audited annual financial statements and notes, as well as management’s discussion and analysis (“MD&A”) for the year ended December 31, 2018 will be available shortly on the System for Electronic Document Analysis and Retrieval (“SEDAR”) and our website (“www.inplayoil.com”).
Message to Shareholders:
InPlay had a strong year in 2018 pursuing a focused light oil growth strategy which also included increasing our land base in both short and long term premier light oil assets. This was achieved without share dilution while maintaining financial flexibility. InPlay achieved organic drill bit light oil and liquids production growth of 22% over 2017 with a capital efficiency of $14,770 per boe/d which we believe is in the top tier among our light oil peers. We successfully grew our Willesden Green land base by adding over 50 net tier one locations effectively replacing five years of drilling inventory. InPlay also added 7,680 acres, a 34% increase, to our land base in the longer term East Duvernay light oil shale play where we have now spent the required capital extending our land tenure four to five years. These long tenured Crown lands allow us to continue to evaluate increasingly positive results from industry delineating the play. InPlay disposed of $27.3 million of non-core facilities and infrastructure as well as non-core, non-operated assets that were producing approximately 250 boe/d in 2018. These dispositions enabled us to increase our position in our top tier plays while also maintaining our strong balance sheet.
Production results and drilling and completion costs continue to exceed our expectations and budget. This was accomplished through strong execution of an efficient, cost effective development program (including drilling pacesetter wells), evolving and optimizing completions utilizing new technology, and smart facility enhancements. This resulted in two increases to our annual production guidance in the second half of 2018 achieving exceptional financial and operational results with a 25% year over year increase in annual operating income to $39.8 million.
The strong performance of the Company’s assets, specifically in Willesden Green, resulted in increased year end reserves (volumes and values) across all categories, including reserves sold during the year and the removal of legacy undeveloped gas locations held by InPlay’s predecessor entity prior to going public in November 2016. The performance is highlighted by proved developed producing reserves (“PDP”) that increased 6% to 8,348 mboe and before tax net present values of future net revenue discounted at 10% (“NPV10 BT”) that increased 7% to $139.2 million. The net result is PDP net asset value (“NAV”) increased 9% to $2.17 per share while generating solid finding, development, and acquisition (“FD&A”) costs of $9.49 per boe, with a recycle ratio of 2.5 times. Total proved plus probable reserves (“TPP”) increased 4% and associated NPV10 BT increased 11% to 27,063 mboe and $387.7 million respectively, resulting in a TPP NAV that increased 11% to $5.81 per share. (See section “Net Asset Value” for these NAV calculations).
These results were achieved in light of the extreme negative market factors that affected Canada’s crude oil pricing market in the fourth quarter of 2018. Revenues were impacted by reduced West Texas Intermediate (“WTI”) pricing, with the peak lows in December at $42.53 per bbl (USD) coupled with significantly widening Edmonton light oil differentials which settled at $34.80 per bbl (USD) in December and averaged $26.30 per bbl (USD) for the quarter. These differentials exacerbated for most of the Canadian oil weighted production companies due to the activities of some large producers who have upstream and downstream operations as well as refiners from the United States, all of whom have the majority of terminal storage, and firm service on pipelines tied up, and in most cases are nominating pipeline volumes above and beyond their producing capacity. InPlay prudently reacted to these deteriorating pricing scenarios by delaying the completions and tie-in of two horizontal wells that were drilled in 2018 to the first quarter of 2019 when we saw the crude oil pricing and differential situation start to improve.
Commodity pricing has quickly corrected positively in the first quarter of 2019 with WTI prices currently at approximately $59.00 per bbl (USD) and Edmonton differentials settling back to more normalized levels in the $4.00-$6.00 per bbl (USD) range. The result for InPlay is that we expect the first quarter of 2019 to be one of our best financial and operational quarters in our history. The solid start to 2019 with pricing and operational results from our capital program has us confirming guidance for the year, which we anticipate will result in top tier organic light oil and liquids growth among our light oil peers of 6 to 10 percent on annual production and 10 to 14 percent on exit production while spending approximately adjusted funds flow from operations.
The Company has continued to evolve by increasing our exposure to two high quality and focused plays. The current high return, quick payout light oil Cardium growth play, and the evolving longer term light oil East Basin Duvernay shale play. This transformation has put us in a much stronger position than when InPlay went public in November of 2016 and places us in an enviable position as a sustainable Canadian Junior Light Oil Exploration & Production (“E&P”) producer with the ability to show top tier growth in this current volatile environment.
Financial and Operating Results:
|(CDN$) (000’s)||Three months ended
|Year ended Dec 31
|Financial (CDN $)|
|Petroleum and natural gas revenue||12,716||18,017||76,419||62,239|
|Cashflow provided by operating activities||4,536||6,460||30,411||22,552|
|Per share – basic and diluted||0.07||0.10||0.45||0.36|
|Adjusted Funds flow from operations(1)||1,721||8,043||27,040||24,974|
|Per share – basic and diluted(1)||0.03||0.13||0.40||0.40|
|Per share – basic and diluted||(0.12||)||(0.11||)||(0.13||)||(0.12||)|
|Exploration and Development Capital expenditures||6,954||26,992||50,206||49,224|
|Property Acquisitions (Dispositions)||(17,305||)||(152||)||(21,470||)||1,067|
|(Net Debt) (1)||(53,670||)||(51,266||)||(53,670||)||(51,266||)|
|Basic & Diluted weighted-average shares||67,987,162||63,875,582||67,911,962||62,688,280|
|(CDN$) (000’s)||Three months ended
|Year ended Dec 31|
|Daily production volumes|
|Crude oil (bbls/d)||2,937||2,503||2,756||2,310|
|Natural gas liquids (bbls/d)||573||371||492||352|
|Natural gas (Mcf/d)||9,065||7,866||8,431||7,857|
|Crude Oil & NGLs ($/bbls)||35.09||62.81||60.49||57.02|
|Natural gas ($/Mcf)||1.66||1.95||1.53||2.38|
|Operating netbacks ($/boe) (1)|
|Oil and Gas sales||27.53||46.79||45.00||42.93|
|Operating Netback (prior to realized derivative contracts)||8.84||26.31||23.43||21.89|
|Realized gain (loss) on derivative contracts||(0.66||)||0.43||(2.42||)||0.77|
|Operating Netback (including realized derivative contracts)||8.18||26.74||21.01||22.66|
(1) “Adjusted funds flow from operations”, “Net Debt” and “Operating netback per boe” do not have a standardized meaning under International Financial Reporting standards (IFRS) and GAAP. “Adjusted funds flow from operations” adjusts for decommissioning obligation expenditures and net change in operating non-cash working capital from net cash flow provided by operating activities. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.
2018 Financial & Operating Highlights:
• The transformation of InPlay continued with strategic acquisitions and dispositions activity throughout the year. Premier lands were added to our focused light oil core asset base while maintaining a strong balance sheet. This effective activity was the driver that allowed us to increase our production guidance twice in the second half of 2018 and includes the following:
- Acquired 6,059 net acres in Q1/2018 in Willesden Green for consideration of $5.5 million which added an additional 50 net tier one drilling locations. 12 (8.6 net) wells have been drilled to date with results that have exceeded our expectations.
- Sold our 100% interest in a non-core natural gas facility and associated infrastructure for $10 million in the Q1/2018 of which InPlay was only using 14% of the throughput capacity.
- Disposed of predominantly non-operated, non-core assets in West Pembina producing 250 boe/d for premium market valuation proceeds of $16.6 million in Q4/2018.
• Capital efficiencies of $14,770 per boe/d were achieved on exploration and development capital spent on drilling, completions, equipping and facilities. The majority of capital was spent in Willesden Green where we drilled 16 (11.2 net) horizontal wells, and in the Duvernay where a 100% vertical stratigraphic test well was drilled (that has been abandoned) and completion of the horizontal well drilled in 2017.
• Annual 2018 light oil and liquids growth is up 22% to 3,248 bbl/day over 2017 reflecting the focused development of our light oil and liquids assets. Annual average 2018 production is up 17% over 2017 to 4,653 boe/day exceeding corporate guidance of 4,600 boe/d day. Production per weighted average basic share increased 8% in 2018 over 2017 and all of the growth was achieved while disposing of 250 boe/d on October 1, 2018 and with the deferral of completions of two horizontal wells drilled in the fourth quarter of 2018 to first quarter of 2019.
• Average fourth quarter 2018 light oil and liquids production is up 22% over fourth quarter 2017 to 3,510 bbl/day, reflecting our focus on our light oil weighted Cardium assets. Fourth quarter 2018 production was up 20% over the fourth quarter 2017 to 5,021 boe/day representing per weighted average share growth of 13%.
• Significant growth occurred in production and reserves in our core Willesden Green area.
- Production grew 107% to over 3,000 boe/day for Q4/2018 compared to just over 1,400 boe/day in Q4/2017 with light oil and liquids weighting of 73%.
- Year end PDP, TP and TPP reserves grew 54%, 59% and 50% to 4,124 mboe, 9,035 mboe and 12,055 mboe respectively.
• Annual revenues increased by 23% to $76.4 million (94% derived from crude oil and natural gas liquids) resulting in operating income profit margins(1) of 52% in 2018.
• Operating income(1) increased by 25% to $39.8 million in 2018 and operating netbacks per boe(1) increased by 7% to $23.43 per boe in 2018 backed by increased oil and liquid weightings, stronger prices and reduced operating costs. This was accomplished even with the extreme market factors affecting crude commodity pricing in the fourth quarter which resulted in operating netbacks of $8.84 per boe versus $28.88 per boe achieved in the first three quarters of 2018.
• Adjusted funds flow from operations(1) increased by 8% to $27.0 million year over year in 2018. This would have increased by 31% to $31.2 million without hedging gains and losses on derivative contracts over the years and results would have been much higher without the severe crude commodity price environment in the fourth quarter.
• Strategic Crown land holdings in the East Duvernay light oil shale play increased by 12 sections for consideration of $1.4 million in the year. The Company now has a significant land position in one of the most exciting new Canadian light oil plays with 30,640 net acres (48.25 net sections). An independent report was prepared for InPlay on this land by qualified land evaluators, Seaton-Jordan & Associates, which resulted in a value of $49.6 million at year-end. (See the section entitled “Net Asset Value”).
(1) Non-GAAP term. See “Non-GAAP Financial Measures” section.
2018 Capital and Operating Overview:
InPlay executed a $50.2 million capital program during 2018, focused on the Willesden Green bioturbated Cardium formation. The Company drilled 12 (8.6 net) extended reach horizontal (“ERH”) wells and 4 (2.6 net) one-mile horizontal wells. The final two Cardium completions were deferred from October of 2018 into 2019 to avoid the poor fourth quarter 2018 Canadian oil prices and add value by selling the flush production period into a time frame with improved pricing. In aggregate, InPlay drilled an equivalent of 23.0 (16.5 net) horizontal miles. The Company completed one Duvernay horizontal well during the second quarter of 2018 and drilled one vertical stratigraphic Duvernay test well in the fourth quarter. By drilling these wells our land tenure has been extended between four to five years. The Company also acquired an additional 12 sections of undeveloped Crown land in the Duvernay area.
InPlay’s focus on developing the Willesden Green bioturbated Cardium assets continued to deliver exceptional results with production volumes and rates consistently exceeding internal estimates. We believe InPlay is delivering top tier capital efficiencies with its capital program where we have managed to achieve some of the shortest spud to rig release days for ERH wells seen to date in the area. Our most recent six 1.5 mile ERH wells have averaged 9.7 drilling days. We have also achieved very consistent drilling performance whereby the maximum deviation from average drilling time of the six 1.5 mile ERH wells has been +/- 0.7 days. Our 1.5 mile ERH wells allow us to access approximately 60% more reservoir while incurring only 20% more in additional capital expenditures compared to a one mile horizontal well. These factors drove improved capital efficiencies on our 2018 capital program to approximately $14,770 per boe/d.
2018 Reserve Highlights:
InPlay’s strong operational results translated into growth in 2018 year-end reserves across all three categories: proved developed producing reserves (“PDP”), total proved reserves (“TP”) and total proved plus probable reserves (“TPP”). These results were achieved even with the reduction of reserves following the October 1, 2018 non-core asset disposition of 579 mboe ($12.0 mm NPV 10 BT) of PDP, 1,817 mboe ($24.5 mm NPV 10 BT) of TP and 2,290 mboe ($34.4 mm NPV 10 BT) of TPP. There was also the elimination of 1,453 mmcf of TP and 2,503 mmcf of TPP respectively associated with legacy undeveloped gas reserves held over from InPlay’s predecessor company.
The Company increased year end net present reserve values resulting in higher year end corporate net asset values (“NAV”) across all categories: Total PDP NPV 10 BT NAV increased 9% year over year to $2.17 per basic share, TP NPV 10 BT NAV increased 16% to $3.83 per basic share and TPP NPV 10 BT NAV increased 11% year over year to $5.81 per basic share. These increases materialized inclusive of a significant reduction in year-end natural gas price deck and with the previously mentioned dispositions. Following are the yearend reserve highlights:
- PDP Increased 6% to 8,348 mboe (oil & liquids 66%)
- TP increased 8% to 18,859 mboe (oil & liquids 71%)
- TPP increased 4% to 27,063 mboe (oil & liquids 73%)
*Year end reserves include Proved developed non-producing reserves (“PDNP”) of 436.2 mboe attributable to the two deferred Willesden Green wells completed in January 2019.
Finding and Development (“FD”) and Finding Development & Acquisition (“FD&A”) Costs per boe(1):
- PDP FD&A costs were $9.49 and F&D costs were $17.80
- TP FD&A costs were $16.94 and F&D costs were $16.58
- TPP FD&A costs were $15.96 and F&D costs were $14.88
- PDP was 2.5 times
- TP was 1.4 times
- TPP was 1.5 times
Reserve Values (BT discounted at 10%):
- PDP value increases 7% to $139 mm and per share net asset value increased 9% to $2.17(2).
- TP value increases 16% to $252 mm and per share net asset value increased 16% to $3.83(2).
- TPP value increases 11% to $388 mm and per share net asset value increased 11% to $5.81(2).
- Results accomplished with Sproule’s overall AECO spot gas price deck dropping 37%, 33% and 21% in years 1, 2 and 3 respectively and 18% for the remaining years thereafter, compared to its 2017 year-end price deck, as well as the significant disposition in reserves, and revisions of the legacy gas assets that will not be drilled.
*Year end reserves include PDNP NPV 10 BT reserve values of $9.4 mm attributable to the two deferred Willesden Green wells completed in January 2019.
- PDP replacement was 126%
- TP replacement was 182%
- TPP replacement was 158%
- PDP reserve life index of 4.9 years
- TP reserve life index of 11.1 years
- TPP reserve life index of 15.9 years
Strong Willesden Green Reserves Results:
- PDP increased 54% to 4,124 mboe with 66% liquids content
- TP increased 59% to 9,035 mboe with 71% liquids content
- TPP increased 50% to 12,055 mboe with 71% liquids content
- PDP NPV 10 BT reserves value increased 60% to $78.9 mm
- TP NPV 10 BT reserve value increased 68% to $128.8 mm
- TPP NPV 10 BT reserve value increased 56% to $180.0 mm
- Reserve Replacement was 269% (PDP), 489% (TP) and 571% (TPP)
- Refer to section “Performance Measures” for the determination of these measures’ calculations
- Refer to section “Net Asset Value” for the determination of these values.
Corporate Reserves Information:
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 2019.
|December 31, 2018
|Crude Oil||Conventional||Oil||BTAX NPV||Future Development||Net
|Reserves Category(2)(3)(4)(5)||& NGLs(1)||Natural Gas||Equivalent||10%||Capital||Wells|
|Proved developed producing||5,477.7||17,222||8,348.0||139,214||–||–|
|Proved developed non-producing||380.6||334||436.2||9,430||–||–|
|Probable developed producing||1,429.9||4,351||2,155.1||25,467||–||–|
|Probable developed non-producing||96.4||130||117.9||2,374||–||–|
|Total proved plus probable(6)||19,643.7||44,518||27,063.4||387,682||239,574||113.3|
- “Oil & NGL” reserves include all light crude oil & medium crude oil volumes, and natural gas liquids volumes.
- 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.
- Based on Sproule’s December 31, 2018, escalated price forecast as outlined in the table herein entitled “Pricing Assumptions”.
- 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.
- 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.
- Totals may not add due to rounding.
Net Asset Value:
|December 31, 2018|
|BTAX NPV 5%||BTAX NPV 10%|
|Net Asset Value (basic)||173,103||2.54||148,058||2.17|
|December 31, 2018|
|BTAX NPV 5%||BTAX NPV 10%|
|Net Asset Value (basic)||335,454||4.91||261,298||3.83|
|December 31, 2018|
|BTAX NPV 5%||BTAX NPV 10%|
|Net Asset Value (basic)||523,919||7.68||396,526||5.81|
- Evaluated by Sproule as at December 31, 2018. The estimated net present value of future net revenue (“NPV”) does not represent fair market value of the reserves.
- Based on Sproule’s forecast prices and costs as of December 31, 2018.
- Duvernay land holdings evaluated by independent third party firm Seaton-Jordan Partners effective December 31, 2018 attributed a value of $49.6 mm ($1,619/acre) for 30,720 net acres. The remaining undeveloped acreage is based on an internal valuation totaling $12.9 mm ($256/acre) for 50,522 net acres.
- Net debt as at December 31, 2018..
- Based upon 68,256,616 total common shares outstanding as at December 31, 2018.
Future Development Costs (“FDCs”):
FDCs increased by $32.0 million on a proved basis and $22.5 million on a proved plus probable basis due to the addition of 10.9 (TP) and 4.9 (TPP) locations as well as a shift to more extended reach drilling locations. Following is a summary of the estimated FDC required to bring InPlay’s undeveloped reserves on production.
|Future Development Capital Costs (amounts in $000,000’s)|
|Total Proved||Total Proved +
|Total undiscounted FDC||185.7||239.6|
|Total discounted FDC at 10% per year||155.2||194.4|
Note: FDC as per Sproule Report based on Sproule forecast pricing as at December 31, 2018
|2016||2017||2018||3 Year Avg|
|Average crude oil price WTI US$/bbl||43.32||50.95||64.76||53.00|
|E&D Capital ($000’s)(2)||10,251||40,679||20,251||–|
|Production boe/day – Full Year||1,940||3,972||4,653||3,522|
|Production boe/day – Q4||2712||4,185||5,021||3,973|
|Operating netback $/boe – FY(1)||17.57||21.89||23.43||21.79|
|Proved Developed Producing|
|Total Reserves mboe||7,304||7,911||8,348||7,854|
|Reserves additions mboe||4,907||2,057||2,135||3,033|
|FD&A (including FDCs) $/boe(2)||18.12||19.77||9.49||16.47|
|FD&A (excluding FDCs) $/boe(2)||18.12||19.77||9.49||16.47|
|Total Reserves mboe||16,579||17,473||18,859||17,637|
|Reserves additions mboe||11,512||2,345||3,084||5,647|
|FD&A (including FDCs) $/boe(2)||14.13||27.88||16.94||16.54|
|FD&A (excluding FDCs) $/boe(2)||7.72||17.35||6.57||8.84|
|Proved Plus Probable|
|Total Reserves mboe||24,486||26,084||27,063||25,878|
|Reserves additions mboe||16,456||3,048||2,678||7,394|
|FD&A (including FDCs) $/boe(2)||11.54||26.17||15.96||14.08|
|FD&A (excluding FDCs) $/boe(2)||5.40||13.35||7.56||6.75|
In 2018, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $14,770 boe/d(6)
- Operating Netback per boe excludes realized gains/ (losses) on commodity derivative contracts. See “Non-GAAP Financial Measures”.
- 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 less capitalized G&A expenses adjusted to exclude undeveloped Duvernay land expenditures acquired with no reserves adjusting for “Acquisition Capital” to exclude in 2018, (and include in 2017) capital expended for acquisitions with effective dates in 2017 but which closed post December 31, 2017 and are included in December 31, 2017 reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2018 TPP = ($50.2 mm E&D – $1.3 mm capitalized G&A – $1.4 mm of Duvernay Crown land acquisitions – $21.5 mm net acquisition/disposition capital -$5.7 mm post December 31, 2017 acquisition capital +$22.5 mm FDC) / (27,063 mboe – 26,084 mboe + 1,698 mboe) = $15.96 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. The -$21.5 mm and -$5.7 of acquisition/disposition capital mentioned above is excluded as well as the corresponding 2,021 mboe of TPP net reserves reduced through acquisitions/dispositions is excluded from the change in reserves in the calculation. See “Non-GAAP Measures”.
- Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2018 TPP = ($23.43/$15.96) = 1.5. 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. See Non-GAAP Measures.
- 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: 2018 TPP = (27,063 mboe -26,084 mboe + 1,698 mboe) / 1,698 mboe = 158%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Non-GAAP Measures.
- RLI is calculated by dividing the reserves in each category by the 2018 average annual production. For example 2018 TPP = (27,063 mboe) / (4,653 boeday) = 15.9 years. See Non-GAAP Measures.
- Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of 2018 to 2017 using a decline rate of 22% over the course of the year, calculated as follows: ($50.2 mm E&D capital – $21.5 mm acquisition/disposition capital – $1.3 mm capitalized G&A – $1.4 mm of Duvernay Crown land acquisitions) / (Q4/2018 production of 5,021 boe/d – Q4/2017 production of 4,185 boe/d + 2018 declined production at 22% of 921 boe/d).
The following tables set forth the benchmark reference prices, as at December 31, 2018, reflected in the Sproule Report. These price assumptions were provided to InPlay by Sproule and were Sproule’s then current forecast at the effective date of the Sproule Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1)
as of December 31, 2018
FORECAST PRICES AND COSTS
|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, 2018.
Following the improvements in crude oil price differentials seen at the beginning of 2019, InPlay initiated its 2019 capital program beginning with the completions of the two ERH horizontal Willesden Green wells that were drilled in 2018. We commenced drilling 2.7 net ERH wells in the first quarter of our estimated 9 net horizontal well drilling program budgeted for 2019. All wells drilled in the first quarter have been completed with initial results in line with previous wells which have exceeded our forecasted type curves.
The Company is on track with our focused capital budget of $36 million for the year drilling approximately 9 net ERH wells with the majority being Cardium wells in Willesden Green. The remaining ERH wells are expected to be drilled and brought on production in the second half of 2019. Our 2019 guidance is maintained with annual average production estimated at 4,900 to 5,100 boe/d (approximately 70% oil & liquids) with growth between 6 and 10 percent for oil and liquids, and on a total boe basis, exit production of 5,400 to 5,600 boe/d (70% oil & liquids) with growth between 10 and 14 percent. This guidance is based on realizing an annual average WTI price of $54.00 per bbl (USD), $1.50 per mcf AECO, a foreign exchange ratio of 0.75 CDN/USD and an Edmonton light sweet differential of ($7.50) per bbl (USD). Strengthening WTI crude oil pricing currently at $59 (USD), above our forecast pricing, in addition to the narrowing of Edmonton light sweet differentials to more normalized levels of $4-$6 (USD) are supportive to our capital program matching estimated adjusted funds flow from operations. This program is expected to continue to yield strong returns with anticipated top quartile light oil production growth amongst our light oil weighted peers.
We thank our employees and directors for their ongoing commitment and dedication and we thank all of our shareholders for their continued interest and support. We are excited about the strong operational results we have achieved to date and look forward to reporting our first quarter 2019 financial and operating results from our ongoing development program in May.