CALGARY, ALBERTA–(Marketwired – March 15, 2017) – Delphi Energy Corp. (TSX:DEE) (“Delphi” or the “Company”) is pleased to announce its financial and operational results, crude oil and natural gas reserves information for the year ended December 31, 2016 and an operations update.
- Achieved a Company record low finding and development cost (“F&D”) for proved producing reserves in 2016 of $10.17 per barrel of oil equivalent (“boe”). Including dispositions in the year finding, development, acquisition and disposition cost (“F,D&A”) for proved producing reserves were $2.19 per boe;
- The net present value, discounted at ten percent, of proved developed producing reserves is $128 million, an increase of 15% compared to 2015.
- Achieved an operating netback(1) of $16.24 per boe resulting in a proved producing recycle ratio(2) of 1.6;
- Reduced Delphi’s 2016 operating costs by 27 percent to $6.40 per boe compared to 2015 operating costs of $8.78 per boe;
- Achieved record low, gross average drilling and completion costs of $7.5 million per well on the six wells drilled in 2016 compared to $8.1 million per well in 2015;
- Total liquid yields increased 26 percent to 92 barrels per million cubic feet (“bbls/mmcf”) in 2016, up from 73 bbls/mmcf in 2015. Plant and field condensate was 67 percent of total liquids in 2016;
- Closed a $60.0 million public offering of 5 year term 10 percent Collateralized Exchange Listed Notes (the “Senior Secured Notes”) redefining the capital structure of the Company;
- Executed a strategic agreement with an existing working interest partner (the “Partner Transaction” or the “Transaction”) for proceeds of $54.6 million (including purchase price adjustments) to accelerate growth of its Bigstone Montney asset; and,
- Net debt was reduced by 29 percent at the end of the 2016 year to $85.9 million, down from $121.7 million at the end of 2015.
RECENT OPERATIONS HIGHLIGHTS
- Delphi’s 16-21-60-23W5 well has produced at an average rate over the first 30 days (“IP30”) of 1,968 barrels of oil equivalent per day (“boe/d”) with a Delphi record field condensate rate of 763 barrels per day (“bbls/d”);
- Recently completed three (2.0 net) horizontal Montney wells at Bigstone, all of which are expected to be on production in the second quarter of 2017; and,
- Drilling operations are continuing into break-up with plans for up to five (3.2 net) horizontal Montney wells ready to complete after spring break-up.
(1) Operating netback is calculated by subtracting royalties, operating and transportation costs from revenues and includes hedging gains or losses.
(2) Recycle ratio is calculated as operating netback divided by F&D costs, including change in future development costs, per boe.
|Three Months Ended
|Twelve Months Ended
|Production||2016||2015||% Change||2016||2015||% Change|
|Field condensate (bbls/d)||1,330||1,606||(17)||1,436||1,440||0|
|Natural gas liquids (bbls/d)||1,125||1,414||(20)||1,183||1,433||(17)|
|Crude oil (bbls/d)||8||7||14||8||27||(70)|
|Total crude oil and natural gas liquids||2,463||3,027||(19)||2,627||2,900||(9)|
|Natural gas (mcf/d)||27,988||34,719||(19)||28,595||39,416||(27)|
|Financial Highlights ($ thousands except per unit amounts)|
|Three Months Ended
|Twelve Months Ended
|2016||2015||% Change||2016||2015||% Change|
|Crude oil and natural gas sales||20,546||18,601||10||69,134||80,275||(14)|
|Realized sales price per boe||31.33||37.09||(16)||25.55||31.43||(19)|
|Adjusted Funds from operations||8,120||13,317||(39)||29,865||42,893||(30)|
|Per share – Basic||0.05||0.09||(44)||0.19||0.28||(32)|
|Per share – Diluted||0.05||0.09||(44)||0.19||0.28||(32)|
|Net earnings (loss)||(25,461)||(23,084)||(10)||(41,114)||(42,525)||(3)|
|Per share – Basic||(0.16)||(0.15)||(7)||(0.26)||(0.27)||4|
|Per share – Diluted||(0.16)||(0.15)||(7)||(0.26)||(0.27)||4|
|Disposition of properties||(52,656)||(13,712)||(284)||(57,239)||(67,578)||15|
|Net capital invested||(30,679)||2,471||(1342)||(3,426)||(10,128)||66|
|Acquisition of undeveloped properties||–||–|
|Acquisition of developed properties||–||–|
|Total capital invested||(30,679)||2,471||(1342)||(3,426)||(10,128)||66|
|December 31, 2016||December 31, 2015||% Change|
|Net debt (1)||85,945||121,664||(29)|
|Shares outstanding (000’s)|
|(1)||Defined as the sum of long term and subordinated debt plus (minus) the working capital deficit (surplus) excluding the current portion of the fair value of financial instruments.|
|(2)||Represents the full dilution of all outstanding options and warrants|
MESSAGE TO SHAREHOLDERS
Throughout 2016, Delphi continued to execute its development plan of its world-class, liquids-rich Montney property (“Bigstone Montney”) located at Bigstone in northwest Alberta, while strengthening the Company’s overall financial position through several strategic initiatives. The Company continues to successfully deliver robust economic returns on its capital projects along with higher cash netbacks, which continue to materially exceed our historical proved producing finding and development costs. Innovations applied to the Company’s completion techniques have resulted in significant increases to the field condensate to natural gas ratios, all while cost-saving initiatives continue to be successfully implemented. In 2016, the inclusion of Senior Secured Notes into the Company’s capital structure along with a new bank syndicate and the Partner Transaction have all contributed to reduce overall debt by 51 percent over the past two years and allowed for the planned acceleration of drilling activity through 2017.
The Company’s successful operating margin growth is a result of the high quality Bigstone Montney asset base, majority ownership in strategic infrastructure, firm take away capacity and proven expertise in developing this liquids-rich asset. Delphi’s strong hedge position has protected cash flow and economic returns through the entire period of lower commodity prices, creating the flexibility to pursue growth initiatives.
Year-over-year average West Texas Intermediate (“WTI”) crude oil prices decreased 11 percent to US $43.39 per barrel. New York Mercantile Exchange (“NYMEX”) natural gas prices averaged US $2.45 per million British thermal units (“mmbtu”) in 2016, down seven percent from the previous year.
Delphi’s commodity price risk management program continues to be an integral part of our financial strategy to protect funds from operations and return on capital employed during periods of price volatility. Despite the prolonged drop in crude oil prices, the Company received $58.61 per barrel for its condensate production in 2016, including a realized risk management gain of $9.97 per barrel for maturing contracts during the period. Delphi’s realized natural gas price for 2016 was $4.45 per million cubic feet (“mcf”), an increase of 11 percent from the comparative period of 2015. The Company’s realized natural gas price was positively influenced by its risk management program and includes a gain of $1.18 per mcf for maturing contracts in the period. In 2016, the Company realized $17.6 million in gains from its risk management program compared to $28.3 million gains during 2015.
Production volumes in 2016 averaged 7,392 boe/d, a 22 percent decrease compared to 2015. A 30 day unscheduled outage at the SemCAMS K3 plant in the second quarter of 2016 reduced annual production volumes by approximately 600 boe/d, together with the major asset dispositions in 2015, which reduced annual production volumes by approximately 1,600 boe/d, largely account for the decrease in 2016 production volumes.
Production volumes in the fourth quarter of 2016 averaged 7,127 boe/d. Weather delays in the third and fourth quarters pushed on-stream dates for two wells of the 2016 program until late December, impacting the fourth quarter production volumes by approximately 600 boe/d. In December 2016, a further reduction of 450 boe/d was incurred as a result of the Partner Transaction. The Company has brought on production seven gross (4.9 net) wells over the past five quarters effectively replacing natural declines over that time period and partially offsetting the Partner Transaction disposition volumes. Delphi’s field operations, well results and current production capability remains on track with its 2017 annual and exit production forecast focusing on accelerated production growth with increased condensate yields.
Delphi’s field condensate weighting as a percentage of 2016 production volumes increased 28 percent from 2015. The Company’s natural gas liquids and field condensate yields increased 26 percent to 92 barrels per million cubic feet in 2016, up from 73 bbls/mmcf in 2015. Field and plant condensate yield averaged 63 bbls/mmcf or 67 percent of the total 92 bbls/mmcf. The Company’s condensate and natural gas liquids weighting is forecast to increase to 40 percent in 2017, from 35 percent in 2016 and 30 percent in 2015.
During 2016, the Company invested gross field capital of $53.8 million. Net of incurred carry capital costs of $9.9 million and a capital closing adjustment of $2.0 million associated with the Partner Transaction, and GORR proceeds of $4.6 million, net field capital was $37.3 million. Delphi spent 80 percent of net field capital on drilling, completing and equipping six gross (4.5 net) Montney wells at Bigstone. During the fourth quarter of 2016, Delphi drilled three gross (2.1 net) wells and brought on production two gross (1.2 net) wells on December 28, 2016. Also in the fourth quarter, the Company closed the Partner Transaction for proceeds of $54.6 million, including adjustments. Total disposition proceeds in 2016 of $57.2 million, (including the full $20.0 million carry capital costs) offset the gross invested field capital of $53.8 million for net proceeds of $3.4 million. In 2015, invested field capital of $57.5 million was offset by $67.6 million of non-core dispositions for net proceeds of $10.1 million.
Funds from operations in 2016 were $29.9 million or $0.19 per basic and diluted share, compared to $42.9 million or $0.28 per basic and diluted share in 2015. The decrease in funds from operations in 2016, as compared to 2015, is primarily due to lower production volumes and commodity prices, as well as reduced gains on financial contracts, all partially offset by lower operating costs. For the twelve months ended December 31, 2016 the field operating netback, excluding hedging gains, increased 22 percent compared to the twelve months ended 2015. Delphi’s Alliance Pipeline marketing arrangement, which commenced in December 1, 2015 to ship the Company’s natural gas into the Chicago market, improved the realized sales price Delphi received for its natural gas. Royalties per boe increased due to less crown royalty credits, and production volumes encumbered with a gross overriding royalty, as a percentage of total volumes, increased over 2015. Operating expenses per boe in 2016 have decreased as a majority of the Company’s production comes from the more efficient Montney play at Bigstone. Transportation expenses have increased as a result of the higher cost of shipping Delphi’s natural gas volumes on the Alliance pipeline system into the Chicago market.
At December 31, 2016, the Company had total net debt of $85.9 million outstanding, a 29 percent decrease from the previous year. The reduction in net debt is a result of the Partner Transaction proceeds of $34.6 million and the total associated $20 million carry capital costs for total proceeds of $54.6 million. At December 31, 2016, Delphi had $53.4 million (net of outstanding letters of credit of $6.6 million) available to be drawn on its senior credit facility. Total net debt has been reduced 51 percent from $173.7 million at December 31, 2014, while the shares outstanding have remained unchanged at 155.6 million. On January 12, 2017, Delphi entered into a new $80 million senior secured revolving credit facility with a banking syndicate comprised of Canadian chartered banks to support an accelerated production growth program.
GLJ Petroleum Consultants Ltd. (“GLJ”), the Company’s independent petroleum engineering firm, has evaluated Delphi’s crude oil, natural gas and natural gas liquids reserves as at December 31, 2016 and prepared a reserves report (the “GLJ Report”) in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” and the “Canadian Oil and Gas Evaluation Handbook”. GLJ’s price forecast dated January 1, 2017 was used in the evaluation.
The following is summary reserves information detailed in the GLJ Report at December 31, 2016:
|Total Natural Gas(1)||Natural Gas Liquids||Oil Equivalent(2)|
|Total Proved Plus Probable||145,840||126,973||12,153||9,623||36,460||30,785|
|(1)||Total Natural Gas includes product types of Shale Gas and Conventional Natural Gas. Product type Shale Gas accounts for approximately 88 percent of Total Proved Natural Gas and 89 percent of Total Proved Plus Probable Natural Gas.|
|(2)||Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1).|
Net Present Value of Future Net Revenue
The estimated future net revenues associated with Delphi’s reserves at December 31, 2016, based on the GLJ January 1, 2017 price forecast, are summarized in the following table. The net present value, discounted at ten percent, of proved developed producing reserves increased 15% compared to 2015. The net present value, discounted at ten percent, of total proved and total proved plus probable reserves decreased by two percent and twelve percent respectively, compared to 2015.
|Net Present Values of Future Net Revenue||Unit Value Before Income|
|Before Income Taxes Discounted At (%/year)(1)||Tax Discounted at|
|Total Proved Plus Probable||507,617||328,021||234,412||179,666||144,600||7.61||1.27|
|(1)||Future net revenues are estimated using forecast prices, costs arising from the anticipated development and production of reserves, net of the associated royalties, operating costs, development costs, and abandonment and reclamation costs. The estimated values disclosed do not necessarily represent fair market value.|
|(2)||Unit values are calculated using net reserves defined as Delphi’s working interest share after deduction of royalty obligations plus Delphi’s royalty interests.|
Future Development Costs
Future development costs (“FDC”) have been reduced by $51 million and $81 million for the total proved and total proved plus probable categories respectively, primarily as a result of dispositions and undeveloped reserve conversions.
The following table provides the future development costs, undiscounted, included in the GLJ Report for total proved and total proved plus probable reserves.
|Total Proved Plus Probable||52,201||26,640||65,496||16,290||550||1,117||162,293|
The following is a summary of GLJ’s January 1, 2017 price forecast used in the evaluation.
The following reconciliation of Delphi’s reserves compares changes in the Company’s gross reserves at December 31, 2015 to the reserves at December 31, 2016, each evaluated in accordance with National Instrument 51-101 definitions.
|Medium||Natural||Natural Gas||Total Oil|
|December 31, 2015||–||95,997||7,892||23,891|
|Extensions and Improved Recovery||–||7,801||637||1,937|
|December 31, 2016||–||76,674||6,434||19,213|
|Medium||Natural||Natural Gas||Total Oil|
|December 31, 2015||–||86,748||7,114||21,572|
|Extensions and Improved Recovery||–||13,460||1,117||3,361|
|December 31, 2016||–||69,128||5,718||17,239|
|Medium||Natural||Natural Gas||Total Oil|
|Proved Plus Probable||(mbbls)||(mmcf)||(mbbls)||(mboe)|
|December 31, 2015||–||182,745||15,005||45,463|
|Extensions and Improved Recovery||–||21,260||1,755||5,298|
|December 31, 2016||–||145,801||12,152||36,452|
|(1)||Gross reserves represent the operated and non-operated working interest share of reserves before deduction of royalties and does not include any royalty interests of the Company.|
|(2)||Total Natural Gas includes product types of Shale Gas and Conventional Natural Gas.|
|(3)||Tables may not add due to rounding.|
Finding and Development Costs
In 2016, corporate F&D costs, including changes in FDC, were $10.17 per boe for proved producing reserves compared to the 2014-16 three year average of $12.40 per boe. Corporate F&D costs in 2016 are $11.25 per boe and $12.73 per boe for total proved and total proved plus probable reserves, respectively. Including acquisitions and dispositions, and the total change in FDC, corporate F,D&A costs for proved developed producing reserves are $2.19 per boe for 2016 and $11.26 per boe for the last three years.
One and three year F,D&A costs in the total proved and total proved plus probable categories are not meaningful as the reduction in future development costs and proceeds from dispositions exceeded actual capital spent in the respective time periods and total reserve additions, including dispositions, technical revisions and economic factors, are also negative.
|2016||2014 – 2016 Totals/Average|
|Proved Producing||Total Proved||Total Proved plus Probable||Proved Producing||Total Proved||Total Proved plus Probable|
|Capital ($ thousands)|
|Exploration and Development (“E&D”) Costs(1)||37,250||37,250||37,250||188,652||188,652||188,652|
|Change in FDC related to E&D||(247)||(28,175)||(23,435)||(2,620)||(78,653)||(43,547)|
|Total E&D Costs||37,003||9,075||13,815||186,032||109,999||145,105|
|Acquisition and Disposition (“A&D”) Costs(1)||(30,618)||(30,618)||(30,618)||(90,254)||(90,254)||(90,254)|
|Change in FDC related to A&D||–||(22,884)||(58,057)||(2,483)||(67,500)||(116,068)|
|Total A&D Costs||(30,618)||(53,502)||(88,675)||(92,737)||(157,754)||(206,321)|
|Total Reserve Discoveries, Extensions & Revisions(2)||3,638||807||1,085||14,999||7,360||9,009|
|Total Acquisitions and Dispositions||(720)||(2,777)||(7,386)||(6,715)||(14,228)||(24,143)|
|Total Reserve Additions||2,918||(1,970)||(6,301)||8,284||(6,868)||(15,134)|
|Finding, Development, Acquisition and Disposition Costs ($/boe)|
|E&D, including change in FDC related to E&D (F&D)||10.17||11.25||12.73||12.40||14.95||16.11|
|E&D and A&D, including change in FDC (F,D&A)||2.19||22.55||11.88||11.26||6.95||4.04|
|(1)||Please refer to page 9 of the Management Discussion and Analysis for the year ended 2016 for explanation of exploration and development costs and acquisition and disposition costs used in the F&D and F,D&A calculations.|
|(2)||Includes extensions and improved recovery, technical revisions, discoveries and economic factors.|
Delphi will release its Annual Information Form by March 31, 2017, which will include all required National Instrument 51-101 reserves disclosure.
Delphi’s planned drilling program in 2017 will more than double as compared to the 2016 program with the addition of a second drilling rig that commenced activity in December 2016. The 2017 development plan contemplates the drilling of 13 gross (8.4 net) Bigstone Montney horizontal wells and the completion, tie-in and well site equipping of 14 gross (9.0 net) wells. It is anticipated that the 2017 development plan will grow production by year-end 2017 to approximately 11,500 boe/d, an anticipated growth increase of 60 percent over 2016. In 2016, the Company continued the trend of reducing drill and completion costs for its horizontal Montney wells at Bigstone reporting a record low gross average of $7.5 million per well compared to $8.1 million per well in 2015, and $10.4 million in 2014.
Results from the Company’s ongoing Montney drilling and completion operations are meeting or exceeding expectations. The combination of new development moving further west on the Company’s Bigstone Montney property, along with Delphi’s third generation frac design, has shown significant improvements to field condensate to natural gas rate yields.
Delphi has several new wells in various stages of operations:
- Wet weather conditions delayed field operations in the fall of 2016, resulting in the fourth and fifth wells (1.2 net) of the 2016 program on production dates being delayed to year-end 2016.
- The sixth and final well of the 2016 program was brought on production at the beginning of February 2017 and has now recorded 30 days of production;
- The first three wells of the 2017 program have been completed and are expected to be on production in the second quarter of 2017;
- The fourth well of the 2017 program has been drilled with completion operations scheduled to commence after spring break-up; and,
- Delphi’s two drilling rigs are currently drilling wells number five and six of the 2017 program, with plans to remain drilling through spring break-up. An additional well from each of the current drilling pads will be drilled totaling four (2.5 net) wells ready for completion in early summer.
The Company is pleased to report initial production results on the 16-21-60-23W5 (“16-21”) (59.3 percent working interest) horizontal Montney well. Over the first 30 days on production, the 16-21 well averaged a total of 1,968 boe/d with a field condensate to sales gas ratio of 134 bbls/mmcf. The 16-21 well has achieved the highest field condensate rate over the first 30 days of all Delphi wells to date with a rate of 763 bbls/d. Total liquid production, including estimated gas plant recovered natural gas liquids of 46 bbls/mmcf sales, accounted for 52 percent of the total sales production rate. This total production rate is 52 percent higher than the immediate offset at 15-21-60-23W5 (brought on production three years ago) validating the benefits of Delphi’s significant enhancements in frac design.
Operations on the Company’s first three wells of the 2017 program are largely finished with all three wells completed with 40 stage fracture stimulations. These wells are expected to be on production in the second quarter of 2017. Delphi’s 15-8-60-23W5 (“15-8”) (65 percent working interest) well was drilled to a total depth of 5,906 metres with a horizontal lateral in the Montney of 2,740 metres. 15-8 was completed with a Company record 5,975 tonnes of sand, resulting in a concentration of 2.2 tonne per horizontal metre. The 15-11-60-23W5 (“15-11”) (65 percent working interest) well was drilled to a total depth of 5,970 metres with a horizontal lateral in the Montney of 2,866 metres. The 13-15-60-23 (65 percent working interest) well was drilled to a total depth of 5,867 metres with a horizontal lateral in the Montney of 2,891 metres. Delphi’s fourth well of the 2017 program at 15-9-60-23W5 (61.8 percent working interest) was drilled to a total depth of 5,912 metres with a horizontal lateral in the Montney of 2,864 metres. A 40 stage completion liner was installed with fracturing operations scheduled to commence after spring break-up.
In early March, the Company commenced drilling its fifth and sixth wells of the 2017 capital program at 13-17-59-22W5 (65 percent working interest) and 13-9-60-23W5 (61.8 percent working interest). An additional well from each of these drilling pad sites will be drilled, resulting in Delphi having four (2.5 net) additional Montney wells ready for completion operations after spring break-up.
Delphi continues to maintain a strong risk management position on both volumes and pricing. The Company believes that reducing commodity price volatility through an active and strategic hedging program both reduces downside cash flow risk while protecting the economics of new capital being deployed. Protecting simple payouts for new wells of approximately one year through a strategic hedging program ensures the ability to effectively reinvest post-payout free cash flow. The Company has approximately 20 million cubic feet per day (“mmcf/d”), or 59% of its 2017 forecast natural gas production hedged at an average price of CDN$4.21 per mmbtu and approximately 1,000 bbls/d of condensate hedged at an average WTI price of CDN$66.70 per barrel (“bbl”).
|Natural Gas||Q1/17||Q2 – Q4/17||2018||2019|
|Percent Hedged *||57%||51%||39%||21%|
|Hedge Price (CDN $/mmbtu)||$4.25||$4.24||$3.83||$3.89|
|Crude Oil||Q1/17||Q2 – Q4/17||2018||2019|
|Percent Hedged *||63%||42%||14%||14%|
|Hedge Price (WTI CDN $/bbl)||$66.51||$66.67||$70.00||$70.00|
* Based on average 2017 production of 33.5 mmcf/d of natural gas and 2,150 bbls/d of field condensate.
The following table highlights the major assumptions with respect to Delphi’s 2017 full year guidance and includes revised 2016 guidance.
|NYMEX Natural Gas Price (US $ per mmbtu)||$3.25||$2.45|
|WTI Oil Price (US $ per bbl)||$55.00||$43.39|
|Natural Gas Liquids Price (CDN $ per bbl)||$28.00||$20.62|
|Foreign Exchange Rate (US/Cdn)||1.33||1.32|
|Net Capital Program ($ million)||$65.0 – $70.0||$37.3|
|Gross Well Count Drilled (net)||13 (8.4)||6.0 (4.2)|
|Gross Well Count On Production (net)||14 (9.0)||6.0 (4.5)|
The Company is forecasting significant absolute and per share growth across all measures during 2017, while maintaining balance sheet strength. 2017 guidance is highlighted by a significant increase in drilling activity funded in part by the $20.0 million carry capital costs relating to the Partner Transaction, of which approximately $9.9 million was incurred in the fourth quarter of 2016.
|2017 Full Year Guidance||2016 Full Year Actuals||Percentage
|Average Production (boe/d)||9,000 – 9,500||7,392||25%|
|Natural Gas (mmcf/d)||32.0 – 35.0||28.6||17%|
|Field Condensate (bbls/d)||2,100 – 2,200||1,436||50%|
|NGL’s (bbls/d)||1,400 – 1,500||1,183||23%|
|Percent Liquids (%)||40||35||14%|
|Production per share (per million shares)||60||47||28%|
|December Average Production (boe/d)||11,000 – 12,000||7,323||57%|
|December Exit Production (boe/d)||11,000 – 12,000||8,600||34%|
|Funds from Operations (“FFO”) ($ million)||$52.0 – $57.0||$29.9||82%|
|Net Debt at December 31 ($ million) (1)||$115.0 – $120.0||$105.0||12%|
|Total Debt / Q4 FFO (annualized)||1.4 – 1.6||3.2||(53%)|
|Bank Debt / Q4 FFO (annualized) (2)||0.7 – 0.8||1.7||(56%)|
|(1)||Net debt includes working capital and the 5-year senior secured notes at $60 million, not the carrying value per the statement of financial position, but excludes outstanding Letters of Credit of $6.6 million.|
|(2)||Bank debt is net debt less the senior secured notes of $60 million.|
Operational momentum continues to build throughout 2017, exiting the year with a very strong fourth quarter and setting up for continued growth into 2018 and beyond. As Delphi ramps up an increased level of field activity in 2017, the Company remains focused on its culture of strong capital discipline as demonstrated over the past three years.
|Production (boe/d)||11,000 – 11,500||7,127||58%|
|Production per share (per million shares)||73||46||59%|
|Q4 FFO ($ million)||$18.0 – $20.0||$8.1||135%|
|Annualized FFO ($ million)||$72.0 – $80.0||$32.5||134%|
|Annualized FFO per share||$0.46 – $0.51||$0.21||130%|
|Cash Netback Including Hedges ($/boe)||$18.00||$12.40||45%|
|Cash Netback Excluding Hedges ($/boe)||$18.50||$9.47||95%|
Delphi’s 2017 capital program is forecast to be $65.0 to $70.0 million targeting an increase in annual production of approximately 25 percent (absolute and per share) to 9,000 to 9,500 boe/d. Annual 2017 funds from operations (“FFO”) are forecast to increase approximately 82 percent (absolute and per share) based on an average WTI oil price of US$55.00 per barrel and an average NYMEX natural gas price of US$3.25 per mmbtu. As a result, the Company’s increasing cash flow is expected to reduce bank debt to annualized fourth quarter 2017 FFO of 0.8 times and total debt to annualized fourth quarter 2017 FFO of 1.5 times. The contemplated 2017 capital program is net of an estimated $10.1 million of carry capital costs remaining from the Partner Transaction.
The 2017 development plan contemplates the drilling of 13 gross (8.4 net) Bigstone Montney horizontal wells and the completion, tie-in and well site equipping of 14 gross (9.0 net) wells. A second rig commenced drilling operations in December 2016 and is expected to remain active throughout the 2017 drilling program, allowing the Company to proceed with pad drilling that will support accelerated drilling activity while realizing further cost savings.
The Company continues to innovate our field operations significantly improving well results. Well stimulation design innovations continue to enhance well productivities, field condensate yields and well economics. Continued Bigstone Montney drilling to the west is resulting in ultra-rich field condensate yields. Field condensate yields in the most recent wells have increased two to four times compared to the average yields realized from the Company’s previous 25 wells. Increased condensate yields of this magnitude on new wells, combined with higher forecast condensate prices in 2017 have the compound result of doubling revenue per boe and increasing unhedged field operating netbacks per boe by as much as three times compared to 2016 netbacks.
Cash costs are forecast to decrease by approximately ten to twelve percent in 2017, with a continued focus on cost saving initiatives and significant production growth. Delphi continues to maintain a strong risk management position on both volumes and pricing.
Delphi has secured the required firm service transportation for 100 percent of forecasted 2017 natural gas production growth. The contracted Alliance full path service to Chicago with its incremental priority interruptible service, together with the existing and incremental 2018 contracted firm TCPL service, will provide the Company with sufficient firm service to handle accelerated growth plans beyond 2017. Delphi’s Bigstone Montney field compression and dehydration facilities are also sufficient for the forecasted growth in 2017.
To handle the Company’s growing production volumes beyond 2017, Delphi is working to efficiently expand its existing Montney field dehydration and compression capacity at East and South Bigstone. Through this effort, Delphi has secured a 20 mmcf/d amine processing equipment package to sweeten a portion of the Montney production for processing at the under-utilized Partner operated Bigstone sweet gas plant located at 14-28-59-22W5, where the Company owns a 25 percent working interest.
Delphi is now well positioned to achieve significant production, cash flow and reserve growth over the near and long term to the benefit of all our stakeholders.
CONFERENCE CALL AND WEBCAST
A conference call and webcast to review 2016 year end results is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, March 16, 2017. The conference call number is 1-844-358-8760. A brief presentation by David J. Reid, President and CEO will be followed by a question and answer period. The conference call will also be broadcast live on the Internet and may be accessed through www.delphienergy.ca or by entering http://edge.media-server.com/m/p/dpxo63f6 in your web browser.
A recorded rebroadcast will be archived and made available on the Company’s website at www.delphienergy.ca or by entering http://edge.media-server.com/m/p/dpxo63f6 in your web browser. Delphi’s annual and fourth quarter 2016 financial statements and management’s discussion and analysis are available on the Company’s website at www.delphienergy.ca and SEDAR at www.SEDAR.com.
This news release does not constitute an offer to sell or a solicitation of any offer to buy the securities in the United States. The securities offered have not been and will not be registered under the U.S. Securities Act of 1933, as amended and will not be offered or sold in the United States absent an exemption from the registration requirements thereof.
About Delphi Energy Corp.
Delphi Energy Corp. is an industry-leading producer of liquids-rich natural gas. The Company has achieved top decile results through the development of our high quality Montney property, uniquely positioned in the Deep Basin of Bigstone, in northwest Alberta. Delphi continues to outperform key industry players by improving operational efficiencies and growing our dominant Bigstone land position in this world-class play. Delphi is headquartered in Calgary, Alberta and trades on the Toronto Stock Exchange under the symbol DEE.