CALGARY, Alberta, Nov. 13, 2018 (GLOBE NEWSWIRE) — Delphi Energy Corp. (“Delphi” or the “Company”) is pleased to announce its financial and operational results for the quarter ended September 30, 2018.
Third Quarter 2018 Highlights
- Achieved the Company’s production guidance for the third quarter, producing 9,514 barrels of oil equivalent per day (“boe/d”) compared to 9,313 boe/d in the comparative quarter of 2017, despite curtailment of approximately 800 boe/d due to unscheduled third party processing plant outages;
- Drilled four (2.60 net) wells, two (1.30 net) of which were brought on production on the last few days of the quarter;
- Field condensate production increased nine and 37 percent in the three and nine months ended September 30, 2018 compared to the same periods in 2017;
- Field condensate and natural gas liquids (“NGLs”) accounted for 72 percent of crude oil and natural gas revenues and 37 percent of production;
- Realized a natural gas price, before risk management contracts and including marketing income, of $3.06 per thousand cubic feet (“mcf”) compared to an average AECO price of $1.19 per mcf as a result of selling approximately 60 percent of our natural gas in Chicago, Illinois, via full-path transportation arrangements and generating marketing income from excess firm Alliance transportation;
- Marketing income generated from excess firm Alliance transportation service added $1.48 per barrel of oil equivalent (“boe”) to cash netback;
- Operating, transportation and general and administrative costs combined are $3.2 million or 21 percent lower than in the second quarter of 2018, and $3.0 million or 20 percent less than in the third quarter of 2017;
- Operating netback before risk management nearly doubled to $23.01 per boe, up from $11.52 per boe in the comparative quarter. Operating netback including risk management increased 36 percent over the comparative quarter to $18.80 per boe;
- Cash netbacks per boe increased by 50 percent over the comparative quarter resulting in adjusted funds flow of $11.6 million, a 53 percent increase over the third quarter of 2017;
- Delphi has WTI crude oil hedges for 2,950 barrels per day (“bbls/d”) (approximately 85% of its liquids production) at C$85.73 per barrel for 2019 and 500 bbls/d at C$90.05 per barrel for 2020; and
- Subsequent to the quarter, Delphi reconfirmed the $105 million borrowing base on its senior credit facility and issued an additional $15 million of ten percent senior secured notes through a private placement. Delphi has significant financial liquidity having only $55 million currently drawn on the senior credit facility.
|FINANCIAL AND OPERATIONAL HIGHLIGHTS|
|Three Months Ended September 30||Nine Months Ended September 30|
|2018||2017||% Change||2018||2017||% Change|
|($ thousands, except per share)|
|Crude oil and natural gas revenues||31,399||25,107||25||100,468||70,940||42|
|Net earnings (loss)||1,252||(4,010||)||(131||)||(9,048||)||8,666||204||)|
|Per share – basic and diluted||0.01||(0.02||)||(150||)||(0.05||)||0.05||(200||)|
|Adjusted funds flow(1)||11,600||7,596||53||37,725||22,525||67|
|Per share – basic and diluted(1)||0.06||(0.04||)||53||0.20||0.13||54|
|Capital expenditures, net of dispositions||19,317||22,529||(14||)||63,892||75,135||(15||)|
|Weighted average shares (000s)|
|(boe conversion – 6:1 basis)|
|Field condensate (bbls/d)||2,196||2,012||9||2,508||1,831||37|
|Natural gas liquids (bbls/d)||1,359||1,367||1||1,451||1,229||18|
|Natural gas (mcf/d)||35,751||35,603||–||35,553||29,652||20|
|Average realized sales prices, before financial instruments and marketing income (1)|
|Field condensate ($/bbl)||79.65||51.08||56||75.58||56.93||33|
|Natural gas liquids ($/bbl)||51.85||33.11||57||46.73||31.12||50|
|Natural gas ($/mcf)||2.67||3.49||(23||)||3.08||3.93||(22||)|
|Crude oil and natural gas revenues||35.87||29.30||22||37.24||32.47||15|
|Marketing income (1)||1.48||–||–||1.34||0.47||185|
|Realized gain (loss) on financial instruments||(4.21||)||2.31||(282||)||(3.50||)||0.90||(489||)|
|Revenue, after realized financial instruments||33.14||31.61||5||35.08||33.84||4|
|General and administrative expenses||(1.65||)||(1.88||)||(12||)||(1.56||)||(2.44||)||(36||)|
|Settlement of unutilized take-or-pay contract||(0.19||)||–||–||(0.19||)||–||–|
|Cash netback (1)||13.25||8.86||50||13.97||10.30||36|
(1) Refer to non-GAAP measures
FINANCIAL HIGHLIGHTS FOR THE QUARTER ENDED SEPTEMBER 30, 2018
Delphi’s continued success in the development of its liquids-rich Montney play, cost reduction initiatives and the Company’s ability to generate marketing income through its excess firm transportation on the Alliance pipeline system have contributed to significant growth in the Company’s adjusted funds flow of 53 percent and 67 percent for the three and nine months ended September 30, 2018 over the respective comparative periods in 2017. Delphi’s operating netback before risk management in the third quarter was $23.01 per boe while the corresponding cash netback was $17.46 per boe, compared to $11.52 per boe and $6.55 per boe in the comparative period in 2017.
Delphi was active in the field drilling four (2.60 net) wells, two (1.30 net) of which were brought on production in the last few days of September. Although these wells had little impact on quarterly production of 9,514 boe/d, they will contribute to expected strong production results in the fourth quarter. Production volumes in the third quarter were negatively impacted by approximately 800 boe/d due to unscheduled third party processing plant outages.
Field condensate production was 2,196 bbls/d, accounting for 23 percent of production on a boe basis and 51 percent of crude oil and natural gas revenues. Total field condensate and natural gas liquids production accounted for 37 percent of production on a boe basis while contributing 72 percent of crude oil and natural gas revenues. In comparison, in the third quarter of 2017, total field condensate and natural gas liquids production accounted for 36 percent of production on a boe basis while contributing 54 percent of crude oil and natural gas revenues.
Operating, transportation and general and administrative costs combined are $3.2 million or 21 percent lower than in the the second quarter of 2018, and $3.0 million or 20 percent less than in the third quarter of 2017. Lower operating and transportation costs are partially due to the commissioning of the amine facility and the corresponding shift of volumes onto the NGTL system.
Delphi shipped approximately 60 percent of its natural gas into the Chicago market and the remainder was sold in Alberta through the NGTL pipeline system. Delphi’s realized natural gas price, before risk management and including marketing income, was $3.06 per mcf, more than double the average AECO benchmark price of $1.19 per mcf. While the shift of volumes from the Chicago market to the AECO market in the third quarter had the impact of reducing the average realized price of our natural gas, it was more than offset by savings in operating and transportation costs and increased marketing income generated from the additional excess Alliance firm transportation. The proportion of natural gas sold in the Chicago market is expected to return to 90 percent once the Alliance lateral pipeline to the Bigstone West gas plant is reactivated which is expected to occur in 2019.
Net debt which includes bank debt, working capital deficiency, senior secured notes, and the unused take-or-pay contract liability at the end of the quarter was $163.4 million. Delphi has significant financial liquidity having only $55 million currently drawn on its $105 million senior credit facility.
NATURAL GAS MARKETING DELIVERING PREMIUM PRICING
Delphi has a total of 57 mmcf/d of firm and priority interruptible service on the Alliance pipeline system and 24 mmcf/d of firm service on the NGTL pipeline system. All of Delphi’s natural gas hedges are focused on the more robust Chicago delivery point. Delphi continues to generate marketing income from the excess service it holds on Alliance through a combination of 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.
COMMODITY RISK MANAGEMENT PROGRAM STABILIZING REALIZED PRICES
The Company has continued its active forward-looking hedging strategy, locking in strong natural gas and WTI pricing into 2019 and 2020. The recent widening of condensate price differentials is generally viewed as a short term issue with differentials normalizing into the second half of 2019.
Delphi’s realized prices for condensate and NGLs are well protected by WTI crude oil hedges, equal to approximately 85 percent of its liquids production, at an average price of C$85.73 per bbl for calendar year 2019 compared to the current strip price of approximately C$73.90 per bbl.
|Commodity Hedges||Q4 2018||2019||2020|
|Natural gas (mmcf/d)||17.4||15.0||3.7|
|Average hedge price (C$/mcf)(2)||$3.64||$3.47||$3.45|
|% of natural gas production hedged(3)||46||39||10|
|Crude oil (bbl/d)||2,100||2,950||500|
|Average hedge price (C$/bbl)||$72.41||$85.73||$90.05|
|% of condensate and NGL production hedged(3)||60||84||14|
|Average hedge price (C$/bbl)||–||$42.82||$41.40|
|% of propane production hedged(3)||–||62||15|
(1) Assumes an FX of 1.327 CAD per USD for the fourth quarter of 2018 and 1.28 CAD per USD for 2019 and 2020.
(2) Includes the impact of NYMEX HH natural gas – Chicago basis hedges.
(3) Based on 38 mmcf/d of natural gas production, 3,500 bbl/d of condensate and NGL production and 650 bbl/d of propane production.
WEST BIGSTONE OPERATIONS CONTINUE TO DELIVER SUPERIOR WELL RESULTS
The delineation success at West Bigstone combined with the anticipated benefits of multi-well pad development are the fundamental drivers behind Delphi’s decision to accelerate 2019 capital spending into the fourth quarter of 2018. While pad development extends the cycle time from spud to first production, the modest impact of the delay is significantly outweighed by the estimated well cost savings and productivity gains expected.
Delphi has finished drilling the first horizontal Montney well on its inaugural four-well pad at 02/15-10-60-24W5 (“02/15-10”) in West Bigstone. Because of operational efficiencies gained through pad development, particularly through the completion of the wells, the Company has installed a hybrid completion liner at 02/15-10 allowing for 80 discrete fracs in the horizontal. Multi-well pad operations allow for a frac program of this scale as it would otherwise be cost prohibitive on a single well pad. The 80 stage completion will be almost 25 percent more stages than Delphi has pumped to date in a single well. The 16-10-60-24W5 (“16-10”) well that came on production in May of 2018, and was a key success leading to pad development at West Bigstone, was completed with 65 stages. Through further frac design innovations and efficiencies inherent in pad operations, the planned 80 stage frac is expected to cost approximately 20 percent less than the 65 stage completion at 16-10. Over the first five months on production, 16-10 has produced 0.6 bcf of raw natural gas and 76,000 bbls of 49 degree API field condensate. The immediate offset to 16-10 at 00/15-10-60-24W5 (“00/15-10”) that tested at similar field condensate rates to the 16-10, has recently been brought on production through the Company’s 100 percent owned Negus processing facility.
Delphi projects that over a three-year period (2019 to 2021) in a scenario where capital spending equates to adjusted funds flow, production would increase by approximately 30 percent and net debt to trailing adjusted funds flow will be reduced to below 2.0 times. In this scenario, Delphi would expect to outspend adjusted funds flow in 2019 and underspend in 2020 and 2021, while drilling 37 wells. With a significant inventory of drilling locations on 128 undeveloped sections of land, Delphi has the potential to considerably increase production and adjusted funds flow from the Bigstone property. It is expected that the Company’s adjusted funds flow growth will continue to outpace overall production growth, as a result of the increasing percentage of condensate and focus on cash cost reductions.
Condensate differentials, which historically have had low volatility, expanded along with differentials for Canadian heavy and light crude oils commencing in September. This was due to a number of factors including a longer than expected shutdown of the Strathcona refinery in Edmonton and seasonal refinery turnarounds in the U.S. Midwest resulting in the filling of storage in Edmonton and the apportionment of crude export pipelines, as well as feeder pipelines bringing crude and condensate to Edmonton. Apportionment of feeder pipelines bringing condensate to Edmonton will continue until storage levels are reduced to normal levels which is expected to take a number of months. While we anticipate that Delphi will be able to sell all its condensate production throughout the period of apportionment, the Company will be impacted by the higher condensate differentials, particularly as the apportioned volumes will be sold on the spot market where we expect higher differentials than for monthly sales. The fundamentals for condensate remain strong, with more than half of demand continuing to be met by higher cost condensate being imported by pipelines and rail. It is still the most under-supplied and highest value commodity Delphi and the industry produces.
Given the Company’s reconfirmed borrowing base of its $105 million senior secured credit facility with only $55 million drawn and its significant in-the-money hedge position on both WTI and Chicago natural gas prices, Delphi remains well positioned to execute its planned capital program on its liquids-rich Montney asset at Bigstone while maintaining financial flexibility.
Delphi’s guidance for production in the fourth quarter of 2018 remains unchanged with the transition to pad drilling. Net debt to adjusted funds flow is projected to increase during the drilling and completion of the four-well pad at West Bigstone but by the second quarter of 2019, as production volumes from the pad materialize, leverage metrics are expected to be reduced below current levels.
Delphi intends to release its 2019 drilling plans and guidance in the first quarter of 2019.
CONFERENCE CALL AND WEBCAST
A conference call and webcast to review 2018 third quarter results is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Wednesday, November 14, 2018. The conference call number is 1-844-358-8760. A brief presentation by David J. Reid, President and CEO, and Mark Behrman, CFO 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 https://edge.media-server.com/m6/p/nr5a8t7c 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 https://edge.media-server.com/m6/p/nr5a8t7c in your web browser. Delphi’s third quarter 2018 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.
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.