Quarterly / Earnings Reports | Fourth Quarter (4Q) Update | Capital Expenditure | Drilling Program - Wells | Capital Expenditure - 2018

Delphi IDs 1H 2018 Budget, Guidance; Touts 77% Condensate Output Jump in 2017

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   |    Wednesday,March 14,2018

[Summary: Delphi Energy reported its 2018 outlook as well as its full year 2017 results.

2018 Plans

- 1H 2018 Capex: $38-45 million (the company spent a total of $107 million in 2017 at the midpoint)

- 1H 2018 Production: 9,800-10,200 BOEPD (up +36% from 2017's 7,336 BOEPD)

Delphi looks to formalize its second half 2018 capital program later in the second quarter.

2017 Highlights - Condensate Production Up 77%

  • Produced 8,401 BOEPD, a 14 percent increase from 7,392 boe/d in 2016.  Average production in the fourth quarter of 2017 increased 35 percent to 9,588 boe/d compared to 7,127 boe/d in the fourth quarter of 2016
  • Field condensate production in the fourth quarter of 2017 increased to 2,374 BPD, a 77% increase from 1,338 bbls/d in the fourth quarter of 2016
  • Field condensate and natural gas liquids (“NGL”) accounted for 58 percent of crude oil and natural gas revenues in 2017 and 64 percent in the fourth quarter]

 

 

 

 

 

 

 

 

ORIGINAL RELEASE:

Delphi Energy Corp. (“Delphi” or the “Company”) (TSX:DEE) is pleased to announce its financial and operational results, crude oil and natural gas reserves information for the year ended December 31, 2017 and an operations update.

2017 HIGHLIGHTS

  • Produced 8,401 barrels of oil equivalent per day (“boe/d”), a 14 percent increase from 7,392 boe/d in 2016.  Average production in the fourth quarter of 2017 increased 35 percent to 9,588 boe/d compared to 7,127 boe/d in the fourth quarter of 2016;
  • Field condensate production in the fourth quarter of 2017 increased to 2,374 barrels per day (“bbls/d”), a 77 percent increase from 1,338 bbls/d in the fourth quarter of 2016;
  • Field condensate and natural gas liquids (“NGL”) accounted for 58 percent of crude oil and natural gas revenues in 2017 and 64 percent in the fourth quarter;
  • Realized a natural gas price of $4.04 per thousand cubic feet (“mcf”) as a result of selling approximately 90 percent of our natural gas in Chicago via full-path transportation arrangements on Alliance and a hedging gain of $0.27 per mcf;
  • Cash netbacks per barrel of oil equivalent (“boe”) increased by eight percent resulting in adjusted funds flow of $36.7 million, a 23 percent increase over 2016. Cash netbacks per boe in the fourth quarter of 2017 increased 29 percent resulting in adjusted funds flow of $14.1 million, a 74 percent increase over the comparative quarter of 2016.
  • Drilled six (3.9 net) successful delineation wells and eleven (7.1 net) successful in-fill wells in the Company’s Bigstone Montney property, as part of a 17 (11.0 net) well drilling program;
  • Acquired 14.5 gross (13.5 net) sections of Montney rights in the greater Bigstone area contiguous to the Company’s current Montney lands;
  • Invested $15.0 million in various infrastructure projects to handle additional sales volumes and provide for reduced operating expenses in 2018 and constructed over 21 kilometres of main gathering and associated fuel gas pipelines and over five kilometres of well tie-in and associated fuel gas pipelines;
  • Increased total proved and total proved plus probable reserves by 40 percent and 33 percent, respectively, from a successful delineation drilling program in 2017;
  • Increased the net present value (discounted at ten percent) of total proved and total proved plus probable reserves by 23 percent and 30 percent respectively;
  • Increased field condensate reserves related to the Company’s Montney shale gas reserves by 76 percent and 68 percent for total proved and total proved plus probable reserves, respectively; and
  • For the 15 (9.6 net) wells brought on production in 2017, achieved a proved developed producing finding and development cost of $14.37 per boe(1).

(1) Includes capital to drill, complete, equip and tie-in of $86.8 million and proved developed producing reserve “extensions and improved recovery” of 6.04 million barrels of oil equivalent (“mmboe”).  Excludes technical revisions associated with other wells.  Includes $5.9 million of 2016 capital and excludes $17.7 million of capital spent in 2017 for drilling and completion of wells not brought on production in 2017.

FINANCIAL AND OPERATIONAL HIGHLIGHTS          
  Three months ended December 31 Twelve months ended December 31
  2017   2016   % Change   2017   2016   % Change  
Financial            
($ thousands, except per share)            
                         
Oil and natural gas revenues 30,896   20,546   50   101,836   69,134   47  
Net earnings (loss) (1,764 ) (25,461 ) 93   6,902   (41,114 )  
Per share – basic and diluted (0.01 ) (0.16 ) 94   0.04   (0.26 )  
Adjusted funds flow(1) 14,144   8,120   74   36,670   29,865   23  
Per share – basic and diluted(1) 0.08   0.05   60   0.21   0.19   11  
Net debt(1) 136,421   85,945   59   136,421   85,945   59  
Capital expenditures, net of dispositions 42,156   (30,679 )   117,292   (3,427 )  
             
Weighted average shares (000s)            
Basic 185,472   155,630     19   173,171   155,540   11  
Diluted 185,472   155,630   19   173,975   155,540   12  
             
Operating            
(boe conversion – 6:1 basis)            
             
Production:            
Field condensate (bbls/d) 2,374   1,338   77   1,968   1,444   36  
Natural gas liquids (bbls/d) 1,315   1,125   17   1,250   1,183   6  
Natural gas (mcf/d) 35,391   27,988   26   31,098   28,595   9  
Total (Boe/d) 9,588   7,127   35   8,401   7,392   14  
             
Average realized sales prices, before financial instruments            
Field condensate ($/bbl) 64.20   57.17   12   59.14   48.64   22  
Natural gas liquids ($/bbl) 47.34   30.42   56   35.42   20.62   72  
Natural gas ($/mcf) 3.39   4.00   (15 ) 3.78   3.28   15  
             
Netbacks ($/boe)            
Crude oil and natural gas revenues 35.03   31.33   12   33.22   25.55   30  
Marketing income (1) 1.63       0.58      
Realized gain (loss) on financial instruments 1.25   2.93   (57 ) 1.00   6.51   (85 )
Revenue, after realized financial instruments 37.91   34.26   11   34.80   32.06   9  
Royalties (2.26 ) (1.89 ) 20   (2.35 ) (2.49 )   (6 )
Operating expense (10.59 ) (9.57 ) 11   (9.60 ) (7.70 ) 25  
Transportation expense (4.62 ) (4.93 ) (6 ) (5.67 ) (5.63 ) 1  
Operating netback (1) 20.44   17.87   14   17.18   16.24   6  
General and administrative expenses (1.39 ) (1.77 ) (21 ) (2.14 ) (2.01 ) 6  
Paid out restricted share units         (0.11 ) 100  
Interest (3.02 ) (3.72 ) (19 ) (3.08 ) (3.09 )  
Cash netback (1) 16.03   12.38   29   11.96   11.03   8  
                         

(1) Refer to non-GAAP measures

OPERATING AND FINANCIAL HIGHLIGHTS FOR THE QUARTER AND YEAR ENDED DECEMBER 31, 2017

Delphi completed a $117.3 million capital program for 2017.  The program included $98.6 million for drilling 17 (11.0 net) wells and completing 16 (10.2 net) wells, along with $15.0 million for expansion of compression, pipeline gathering and water disposal facilities and $2.2 million for the acquisition of 13.5 net sections of land in the Bigstone area .  In addition, Delphi acquired a 17 million cubic feet per day (“mmcf/d”) amine processing package to sweeten natural gas from the Montney and allow it to be processed at a Company owned facility rather than through third-party processers.  Commissioning of the amine facility is planned for the second quarter of 2018.  Capital spending in the fourth quarter net of dispositions was $42.2 million and included the drilling of four (2.6 net) wells and the completion of five (3.2 net) wells.  The drilling program in 2017 included six (3.9 net) delineation wells, all of which were successful.  The successful delineation wells and investment in facilities have positioned the Company for profitable growth.

Average production was 8,401 boe/d for the year and 9,588 boe/d for the fourth quarter; increases of 14 and 35 percent over the corresponding periods in 2016.  Field condensate production in the fourth quarter was 2,374 bbls/d, an increase of 77 percent over the same period in 2016.  It comprised 25 percent of production on a boe basis compared to 19 percent in the fourth quarter of 2016.  While comprising 25 percent of production, field condensate generated 45 percent of crude oil and natural gas revenues.  Similarly, field condensate and NGL production in the fourth quarter comprised 38 percent of total production and 64 percent of crude oil and natural gas revenues.

Annual crude oil and natural gas revenues were $101.8 million, an increase of 47 percent over 2016 due to both increased production and higher realized prices.  Crude oil and natural gas revenues in the fourth quarter were $30.9 million, an increase of 50 percent over the same period in 2016.

The operating netback was $17.18 per boe in the year and $20.44 per boe in the fourth quarter while the corresponding cash netbacks were $11.96 per boe and $16.03 per boe, respectively. Annual adjusted funds flow increased 23 percent from the prior year to $36.7 million or $0.21 per basic and diluted share.  Adjusted funds flow in the fourth quarter increased 74 percent to $14.1 million or $0.08 per basic and diluted share.

The borrowing base of Delphi’s senior credit facility was increased by $15.0 million to $95.0 million in the fourth quarter and a third bank joined the lending syndicate.  Bank debt at the end of the year was $26.9 million and outstanding letters of credit were $7.3 million, leaving $60.8 million available to be drawn. Net debt at the end of the year was $136.4 million resulting in a net debt to adjusted funds flow ratio of 2.4 times based on annualized fourth quarter adjusted funds flow of $56.6 million.

NATURAL GAS MARKETING AND HEDGING

Given the high liquids content of Delphi’s production, natural gas accounted for only 36 percent of crude oil and natural gas revenues in the fourth quarter despite the fact that Delphi realized a natural gas price before hedging gains of $3.39 per mcf compared to an AECO price of $1.69 per mcf.

Over 90 percent of Delphi’s natural gas is sold in the Chicago market via firm service on the Alliance pipeline system.  Approximately 60 percent of the expected Chicago sales volumes in 2018 are hedged with NYMEX Henry Hub gas swaps for an average of 19,826 million British thermal units per day (“mmbtu/d”) at an average price of US$3.08 or C$3.85 per million British thermal units (“mmbtu”), based on an exchange rate of 1.25 CAD per USD.  Hedging gains added $0.47 per mcf to Delphi’s realized natural gas price in the fourth quarter of 2017.

Delphi has a total of 57.3 mmcf/d of firm and priority interruptible service on Alliance compared to total average gas production of 35.4 mmcf/d in the fourth quarter of 2017.  Delphi generates marketing income on excess service through temporary assignment to other shippers at a premium over cost or through the purchase of natural gas in Alberta or British Columbia for sale in Chicago.

As a hedge to condensate and other natural gas liquids prices that are correlated to WTI crude oil prices, Delphi has an average of 2,238 bbls/d of WTI swaps in 2018 with an average fixed price of C$71.60 per barrel. 

RESERVES SUMMARY

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, 2017 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, 2018 was used in the evaluation.  Company gross reserves in the total proved and total proved plus probable categories increased 40 percent and 33 percent respectively, compared to 2016.

The following is a summary of reserves information detailed in the GLJ Report at December 31, 2017:

  Conventional 
Natural Gas
Shale Gas Natural Gas Liquids Oil Equivalent(1)
  Company Company Company Company Company Company Company Company
  Gross Net Gross Net Gross Net Gross Net
Reserves Category (mmcf) (mmcf) (mmcf) (mmcf) (mbbls) (mbbls) (mboe) (mboe)
Proved                
Producing 7,448 6,578 50,608 44,686 5,139 3,851 14,815 12,395
Developed Non-Producing 922 859 1,782 1,665 185 162 636 583
Undeveloped 41,540 38,906 4,479 4,021 11,403 10,505
Total Proved 8,370 7,437 93,931 85,257 9,803 8,034 26,853 23,483
Total Probable 6,784 6,099 76,377 68,515 7,772 6,172 21,633 18,608
Total Proved Plus Probable 15,154 13,536 170,307 153,771 17,576 14,206 48,486 42,091
                 

(1) 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).
(2) Tables may not add due to rounding.

Net Present Value of Future Net Revenue

The estimated future net revenues associated with Delphi’s reserves at December 31, 2017, based on the GLJ January 1, 2018 price forecast, are summarized in the following table. The net present value of future net revenues, discounted at ten percent, from total proved and total proved plus probable reserves increased by 23 percent and 30 percent respectively, compared to 2016.

  Net Present Values of Future Net Revenue Unit Value Before Income
  Before Income Taxes Discounted At (%/year)(1) Tax Discounted at
            10%/year(2)
  0% 5% 10% 15% 20% $/boe $/mcfe
($ thousands)              
Proved              
Producing 195,971 161,745 138,322 121,706 109,423 11.16 1.86
Developed Non-Producing 11,431 9,352 7,906 6,867 6,094 13.56 2.26
Undeveloped 145,793 85,602 49,797 27,239 12,279 4.74 0.79
Total Proved 353,195 256,699 196,025 155,811 127,795 8.35 1.39
Total Probable 336,224 182,254 109,375 70,826 48,419 5.88 0.98
Total Proved Plus Probable 689,418 438,952 305,400 226,637 176,215 7.26 1.21
               

(1) Future net revenues are estimated using forecast prices, costs arising from the anticipated development and production of reserves, 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.
(3) Tables may not add due to rounding.

Future Development Costs

Future development costs (“FDC”) have increased by $92.0 million and $113.0 million for the total proved and total proved plus probable categories respectively, primarily as a result of new undeveloped locations being booked offsetting the successful delineation wells drilled in 2017.

The following table provides the future development costs, undiscounted, included in the GLJ Report for total proved and total proved plus probable reserves.

($ thousands) 2018 2019 2020 2021 2022 Rem Total
Total Proved 73,580 55,162 21,417 138 146 150,443
Total Proved Plus Probable 73,580 84,533 98,781 16,576 550 949 274,967
               

Forecast Prices

The following is a summary of GLJ’s January 1, 2018 price forecast used in the evaluation.

  Natural Gas Oil      
  AECO/NIT NYMEX Edmonton NYMEX Pentanes Plus   Exchange
  Spot Henry Hub Light WTI Edmonton Inflation Rate
Year $CDN/MMBtu $US/MMBtu $CDN/bbl $US/bbl $CDN/bbl % $US/$CDN
2018 2.20 2.85 70.25 59.00 76.42 2.0 0.790
2019 2.54 3.00 70.25 59.00 74.68 2.0 0.790
2020 2.88 3.25 70.31 60.00 74.38 2.0 0.800
2021 3.24 3.50 72.84 63.00 77.16 2.0 0.810
2022 3.47 3.70 75.61 66.00 79.88 2.0 0.820
2023 3.58 3.86 78.31 69.00 82.53 2.0 0.830
2024 3.66 3.94 81.93 72.00 86.14 2.0 0.830
2025 3.73 4.02 85.54 75.00 89.76 2.0 0.830
2026 3.80 4.10 88.35 77.33 92.57 2.0 0.830
2027 3.88 4.18 90.22 78.88 94.43 2.0 0.830
2028+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 2.0 0.830
               

Reserves(1) Reconciliation

The following reconciliation of Delphi’s reserves compares changes in the Company’s gross reserves at December 31, 2016 to the reserves at December 31, 2017, each evaluated in accordance with National Instrument 51-101 definitions.  Negative technical revisions and economic factors to the shale gas and associated natural gas liquids product types were solely comprised of shale gas and the associated plant extracted natural gas liquids.  Technical revisions and economic factors related to field condensate (included in the “associated natural gas liquids” product type) were positive at 73 mboe and 54 mboe for total proved and total proved plus probable, respectively.

  Shale Gas Conventional Natural Gas  
  Shale Associated Natural Gas Natural Associated Natural Gas Total Oil
  Gas Liquids Gas Liquids Equivalent
Proved (mmcf) (mbbls) (mmcf) (mbbls) (mboe)
December 31, 2016 67,316   6,189   9,357   245   19,213  
Extensions and Improved Recovery 43,199   4,882   0   0   12,082  
Technical Revisions (6,854 ) (370 ) 811   38   (1,339 )
Discoveries          
Acquisitions          
Dispositions          
Economic Factors (7 ) (1 ) (173 ) (4 ) (35 )
Production (9,724 ) (1,126 ) (1,626 ) (49 ) (3,067 )
December 31, 2017 93,931   9,574   8,370   230   26,853  
           
  Shale Gas Conventional Natural Gas  
  Shale Associated Natural Gas Natural Associated Natural Gas Total Oil
  Gas Liquids Gas Liquids Equivalent
Probable (mmcf) (mbbls) (mmcf) (mbbls) (mboe)
December 31, 2016 62,193   5,500   6,934   218   17,239  
Extensions and Improved Recovery 24,872   2,650   0   0   6,795  
Technical Revisions (10,584 ) (605 ) (3 ) 21   (2,349 )
Discoveries          
Acquisitions          
Dispositions          
Economic Factors (104 ) (8 ) (147 ) (3 ) (53 )
Production          
December 31, 2017 76,377   7,536   6,784   236   21,633  
       
  Shale Gas Conventional Natural Gas  
    Associated   Associated  
  Shale Natural Gas Natural Natural Gas Total Oil
  Gas Liquids Gas Liquids Equivalent
Proved Plus Probable (mmcf) (mbbls) (mmcf) (mbbls) (mboe)
December 31, 2016 129,509   11,689   16,292   464   36,452  
Extensions and Improved Recovery 68,071   7,532   0   0   18,877  
Technical Revisions (17,438 ) (976 ) 808   59   (3,689 )
Discoveries          
Acquisitions          
Dispositions          
Economic Factors (111 ) (9 ) (320 ) (8 ) (88 )
Production (9,724 ) (1,126 ) (1,626 ) (49 ) (3,067 )
December 31, 2017 170,307   17,110   15,154   466   48,486  
                     

(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) Tables may not add due to rounding.

Finding and Development Costs

In 2017, Delphi brought 15 gross (9.6 net) wells on production.  Capital to drill, complete, equip and tie-in these wells totaled $86.8 million which includes $5.9 million of capital spent on these wells in 2016 and excludes $17.7 million of capital spent in 2017 for drilling and completion of wells not brought on production in 2017.  Company gross proved developed producing reserve additions (classified as extensions and improved recovery) for these wells was 6.04 mmboe resulting in a finding and development cost of $14.37 per boe.  Finding and development costs for proved and proved plus probable reserves for 2017 and the last three years are presented below.

Three year average finding, development and acquisition costs in the total proved category is not meaningful as total reserve additions are negative.  Three year average finding, development and acquisition costs in the total proved plus probable category is not meaningful as total costs and reserve additions are both negative.  The Company disposed of both its Wapiti and Hythe properties in 2015 and certain interests in Bigstone through a transaction with an industry partner in 2016.

  2017   2015 – 2017 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) 108,829   108,829   108,829   196,630   196,630   196,630  
Change in FDC related to E&D 138   92,182   112,674   (3,967 ) (15,218 ) 9,814  
Total E&D Costs 108,967   201,011   221,503   192,663   181,412   206,444  
             
Acquisition and Disposition (“A&D”) Costs(1) (1,595 ) (1,595 ) (1,595 ) (92,892 ) (92,892 ) (92,892 )
Change in FDC related to A&D       (2,483 ) (65,807 ) (126,267 )
Total A&D Costs (1,595 ) (1,595 ) (1,595 ) (95,375 ) (158,699 ) (219,159 )
             
Total Costs 107,372   199,416   219,908   97,288   22,713   (12,715 )
             
Reserves (mboe)            
Total Reserve Discoveries, Extensions & Revisions(2) 4,673   10,707   15,101   12,188   7,692   9,365  
Total Acquisitions and Dispositions       (6,846 ) (14,513 ) (25,976 )
             
Total Reserve Additions 4,673   10,707   15,101   5,342   (6,821 ) (16,612 )
         
E&D, including change in FDC related to E&D (F&D) 23.32   18.77   14.67   15.81   23.58   22.04  
E&D and A&D, including change in FDC (F,D&A) 22.98   18.62   14.56   18.21   (3.33 ) 0.77  
                         

(1) Capital invested has been reduced by $10.1 million for capital carry costs incurred in 2017 as part of the transaction on the Bigstone Montney asset announced on November 8, 2016.  
(2) Includes extensions and improved recovery, technical revisions, discoveries and economic factors.

Delphi will release its Annual Information Form by April 2, 2018, which will include all required National Instrument 51-101 reserves disclosure.

OPERATIONS UPDATE

The Company brought two (1.3 net) wells on production in February 2018, the first wells to come on production since November 2017.  In one of these wells a new ball drop frac liner was successfully tested in a portion of the horizontal lateral.  This new frac system will accommodate more frac stages and higher frac pump rates as well as simplifying wellbore clean-out operations, if needed.

Delphi has completed its planned winter drilling program with four gross (2.6 net) wells having been drilled prior to March.  Completion operations have commenced on the first well at 16-10-60-24W5 (“16-10”).  16-10 was drilled to a total depth of 5,994 metres and is the western-most well the Company has drilled in over six years.  The well will be completed through a 65-stage hybrid frac design as part of the Company’s sixth generation frac design utilizing 30 percent more discrete stages and 30 percent more sand than used previously.  The frac crew will remain in the field with plans to complete the remaining three 2018 wells as weather permits. 

All major equipment for the Company’s amine sweetening plant is on location and plans remain on-track for the construction and commissioning of the project at the 7-11-60-23W5 compression and dehydration Montney facility.  When brought on-line in the second quarter of 2018, up to 17 mmcf/d of gross raw sweetened Montney gas will be processed at the Repsol operated Bigstone Gas Plant where the Company owns a 25% working interest.  This will significantly reduce operating costs for the portion of Montney gas that gets processed at this plant.

Delphi continues to explore other initiatives to reduce the cost structure of its Bigstone Montney operation.  Pipeline infrastructure for field condensate and water handling are top priorities as these have the potential to significantly reduce associated operating costs and reduce or eliminate reliance on trucking.

OUTLOOK AND 2018 GUIDANCE

Delphi has maintained a high level of drilling activity over the past 15 months with 21 new wells drilled, increasing the total number of wells drilled on its 169 sections of Montney acreage to 52 over the past 5 years. This increased pace of capitalization has materially de-risked the overall acreage with several successful delineation wells to the south and west portions of its acreage.

Although expectations are well defined on the eastern portions of the lands, increased delineation drilling to the west will be beneficial in defining a “richer” condensate type curve expectation. Nine wells have now been drilled on the west side with greater than 90 days of production where the Company continues to enhance its completion techniques from the observed production results.

The Company views this initial success moving west to acreage that is yielding 200 to 300 bbls/mmcf of field condensate as very positive with an expectation of increased margin growth and enhanced return on capital.

With the two most recent wells on-stream, Delphi’s production over the last 7 days has averaged approximately 10,800 boe/d (27 percent condensate and 15 percent NGL’s) based on field estimates.  The Company also has five new wells in various stages of completion operations with expectations for all wells to commence production by early third quarter.  This puts the Company in an excellent position to pause its drilling program through spring breakup to evaluate the production performance of the new wells to best plan the second half of the 2018 capital program.  As such the Company is providing guidance for the first half of 2018 only at this time, giving full consideration to the scheduled production downtime associated with ongoing completion operations and the construction and commissioning of the amine processing facility. Delphi looks to formalize its second half 2018 capital program later in the second quarter.

The following table highlights the major assumptions with respect to Delphi’s guidance for the first half of 2018.

  2018 First 
Half Guidance
Net Capital Program ($ million) $38 – $45
Gross Well Count Drilled (net) 4 (2.6)
Gross Well Count On Production (net) 5 (3.3) – 7 (4.6)
   
  2018 First Half Guidance 2017 First Half
 Actuals
% Change
Average Production (boe/d) 9,800 – 10,200 7,336 36
Natural Gas (mmcf/d) 35.0 – 37.0 26.6 35
Field Condensate (bbls/d) 2,350 – 2,450 1,738 38
NGL’s (bbls/d) 1,470 – 1,530 1,160 29
Percent Liquids (%) 40 40
Adjusted Funds Flow (“AFF”) $25.0 – $27.0 $15.2 71
Cash Netback (per boe, excluding hedges) $14.25 $11.43 25
Net Debt (1) (2) $149.0 – $154.0 $97.8 55
Net Debt / AFF (annualized) 2.9 – 3.0 3.2  
       

(1) Based on WTI crude oil price of $63 per barrel, NYMEX Henry Hub natural gas price of $2.80 per mmbtu and FX of 1.27 CAD per USD.  
(2) Net debt is defined as the sum of bank debt, senior secured notes and the long term portion of unutilized take-or-pay contract plus (minus) the working capital deficit (surplus) excluding the current portion of the fair value of the financial instruments.

Delphi remains well positioned with a high quality resource base supported by strategic infrastructure and a large drilling inventory, a strategic “long Alliance Chicago” natural gas marketing strategy, and a strong commodity hedge position.


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May 22, 2018


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