Delphi Energy Releases Year End 2015 Reserves

CALGARY, ALBERTA--(Marketwired - Feb. 29, 2016) - Delphi Energy Corp. ("Delphi" or the "Company") (TSX:DEE) is pleased to report its crude oil and natural gas reserves information for the year ended December 31, 2015.

While remaining focused on its large-scale Montney project at Bigstone, the Company successfully streamlined its business in 2015 through two major asset dispositions. The dispositions represented approximately 26 percent of the Company's total proved plus probable reserves at December 31, 2014, and 2,600 barrels of oil equivalent per day ("boe/d") or 26 percent of the Company's production capability in 2015 and resulted in a 30 percent reduction in debt to $121.7 million at December 31, 2015.

At December 31, 2015, the Montney reserves at Bigstone represent approximately 95 percent of the Company's total proved and total proved plus probable reserves and approximately 90 percent of its current production capability.

Highlights

• Achieved average corporate production in 2015 of 9,469 boe/d with the Montney representing 70 percent or 6,590 boe/d. Fourth quarter corporate production averaged 8,814 boe/d with the Montney representing 79 percent or 6,924 boe/d;
  
  
• Invested capital of $50.6 million drilling 6.0 gross (5.3 net) Montney horizontal wells during 2015. The capital program was directed at infill locations to minimize capital spending on infrastructure. All Montney locations drilled were previously booked as undeveloped locations. Disposition proceeds during the year totaled $60.7 million;
  
  
• Reduced total future development costs ("FDC") for total proved and total proved plus probable reserves by $122.1 million and $147.6 million, respectively, as a result of dispositions, reserve category reclassifications resulting from the infill drilling program, undeveloped locations removed from the report due to economic considerations and realized capital cost reductions;
  
  
• Added 5.4 million boe (3.9 million boe after technical revisions) of proved producing reserves through its 2015 capital program. Excluding reserves associated with the dispositions, the Company replaced 110 percent of the 3.5 million boe produced in 2015. Proved producing Montney reserves increased 19 percent to 11.6 million boe;
  
  
• Achieved corporate finding and development costs ("F&D"), including changes in FDC, of $12.04 per boe for proved producing reserves compared to the 2013-15 three year average of $14.54 per boe. With a realized operating netback⁽¹⁾ of $16.45 per boe, achieved a proved producing recycle ratio⁽²⁾ of 1.4 times;
  
  
• For the Montney program, Delphi achieved F&D costs, including changes in FDC, of $10.12 per boe for proved producing reserves compared to the 2013-15 three year average of $13.41 per boe; and
  
  
• Achieved gross average drill and complete costs on the 6 wells drilled in 2015 of $8.1 million per well compared to a gross average of $10.2 million per well in 2014. Costs have been further reduced to an average of $7.0 million on the most recent three wells.
  
  ⁽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 per boe divided by F&D or FD&A costs, including change in FDC, per boe.
  
  

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, 2015 and prepared a reserves report ("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, 2016 was used in the evaluation.

The following is summary reserves information detailed in the GLJ Report at December 31, 2015:

			Total Natural Gas(1)				Natural Gas Liquids				Oil Equivalent(2)
			Company		Company		Company		Company		Company		Company
			Gross		Net		Gross		Net		Gross		Net
Reserves Category			(mmcf)		(mmcf)		(mbbls)		(mbbls)		(mboe)		(mboe)
Proved
	Producing		53,814		45,089		4,030		2,611		12,999		10,126
	Developed Non-Producing		2,102		1,810		146		91		496		393
	Undeveloped		40,082		37,037		3,716		2,900		10,396		9,073
Total Proved			95,998		83,937		7,892		5,602		23,891		19,592
Total Probable			86,749		77,926		7,114		5,100		21,572		18,088
Total Proved Plus Probable			182,745		161,862		15,005		10,703		45,463		37,680
(1) Total Natural Gas includes product types of Shale Gas and Conventional Natural Gas. Product type Shale Gas accounts for approximately 94 percent of Total Proved Natural Gas and 95 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, 2015, based on the GLJ January 1, 2016 price forecast, are summarized in the following table.

			Net Present Values of Future Net Revenue										Unit Value Before Income
			Before Income Taxes Discounted At (%/year)(1)										Tax Discounted at
													10%/year(2)
($ thousands)			0%		5%		10%		15%		20%		$/boe		$/mcfe
Proved
	Producing		167,197		134,159		112,019		96,575		85,321		11.06		1.84
	Developed Non-Producing		4,343		2,837		1,870		1,222		766		4.76		0.79
	Undeveloped		125,890		76,716		48,169		30,588		19,155		5.31		0.88
Total Proved			297,431		213,712		162,059		128,385		105,242		8.27		1.38
Total Probable			331,428		176,290		103,092		63,947		40,783		5.70		0.95
Total Proved Plus Probable			628,859		390,002		265,151		192,332		146,026		7.04		1.17
(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 have been reduced by $122.1 million and $147.6 million for the total proved and total proved plus probable categories, respectively as a result of dispositions, undeveloped reserve conversions, reduced forecast development costs and FDC related to locations removed from the report due to economic considerations.

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

($ thousands)		2016		2017		2018		2019		2020		Rem		Total
Total Proved		26,700		36,692		45,335		-		-		593		109,320
Total Proved Plus Probable		50,100		51,240		123,053		17,621		459		1,312		243,785

Forecast Prices

The following is a summary of GLJ's January 1, 2016 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
2016		2.76		2.60		55.86		44.00		60.79		2.0		0.73
2017		3.27		3.10		64.00		52.00		68.48		2.0		0.75
2018		3.45		3.30		68.39		58.00		73.17		2.0		0.78
2019		3.63		3.50		73.75		64.00		78.91		2.0		0.80
2020		3.81		3.70		78.79		70.00		84.30		2.0		0.83
2021		3.90		3.90		82.35		75.00		88.12		2.0		0.85
2022		4.10		4.10		88.24		80.00		94.41		2.0		0.85
2023		4.30		4.30		94.12		85.00		100.71		2.0		0.85
2024		4.50		4.50		96.48		87.88		103.24		2.0		0.85
2025		4.60		4.60		98.41		89.63		105.30		2.0		0.85
2026+		+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr		2.0		0.85

Reserves⁽¹⁾ Reconciliation

The following reconciliation of Delphi's reserves compares changes in the Company's Gross reserves at December 31, 2014 to the reserves at December 31, 2015, each evaluated in accordance with National Instrument 51-101 definitions.

		Light and		Total
		Medium		Natural		Natural Gas		Total Oil
		Crude Oil		Gas(2)		Liquids		Equivalent
Proved		(mbbls)		(mmcf)		(mbbls)		(mboe)
December 31, 2014		19		181,458		12,641		42,903
Extensions and Improved Recovery		-		10,528		907		2,662
Technical Revisions		-		(9,893)		(812)		(2,462)
Discoveries		-		-		-		-
Acquisitions		-		-		-		-
Dispositions		(7)		(54,118)		(2,710)		(11,736)
Economic Factors		(2)		(17,605)		(1,086)		(4,022)
Production		(10)		(14,372)		(1,049)		(3,454)
December 31, 2015		-		95,997		7,892		23,891
		Light and		Total
		Medium		Natural		Natural Gas		Total Oil
		Crude Oil		Gas(2)		Liquids		Equivalent
Probable		(mbbls)		(mmcf)		(mbbls)		(mboe)
December 31, 2014		5		131,662		9,477		31,426
Extensions and Improved Recovery		-		(5,615)		(538)		(1,474)
Technical Revisions		-		(14,919)		(1,078)		(3,565)
Discoveries		-		-		-		-
Acquisitions		-		-		-		-
Dispositions		(7)		(31,815)		(1,544)		(6,854)
Economic Factors		2		7,436		797		2,039
Production		-		-		-		-
December 31, 2015		-		86,749		7,114		21,572
		Light and		Total
		Medium		Natural		Natural Gas		Total Oil
		Crude Oil		Gas(2)		Liquids		Equivalent
Proved Plus Probable		(mbbls)		(mmcf)		(mbbls)		(mboe)
December 31, 2014		24		313,120		22,118		74,329
Extensions and Improved Recovery		-		4,913		369		1,188
Technical Revisions		-		(24,813)		(1,891)		(6,026)
Discoveries		-		-		-		-
Acquisitions		-		-		-		-
Dispositions		(14)		(85,934)		(4,254)		(18,590)
Economic Factors		-		(10,169)		(289)		(1,983)
Production		(10)		(14,372)		(1,049)		(3,454)
December 31, 2015		-		182,745		15,005		45,463
(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.

In the total proved and total proved plus probable reserve categories of the report for the year ended December 31, 2015 negative revisions associated with both non-Montney and Montney reserves were reported due to both economic factors and technical revisions.

Finding and Development Costs

In 2015, corporate finding and development costs ("F&D"), including changes in FDC, were $12.04 per boe for proved producing reserves compared to the 2013-15 three year average of $14.54 per boe. Three year average corporate F&D costs are $12.31 per boe and $10.99 per boe for total proved and total proved plus probable reserves respectively. Including acquisitions and dispositions, three year average corporate finding, development, acquisition and disposition ("F,D&A") costs are $18.33 per boe, $16.81 per boe, and $17.01 per boe for proved producing, total proved and total proved plus probable reserves respectively.

One year F&D and one year F,D&A costs in the total proved and total proved plus probable categories are not meaningful in 2015 as the reduction in future development costs from 2014 to 2015 exceeded actual capital spent and total reserve additions, including technical revisions and economic factors, are also negative. One year F,D&A costs in the proved producing category is also not meaningful as disposition proceeds exceeded actual capital spent and total reserve additions are also negative.

		2015						2013 - 2015 Totals/Average
						Total						Total
		Proved		Total		Proved plus		Proved		Total		Proved plus
		Producing		Proved		Probable		Producing		Proved		Probable
Capital ($ thousands)
Exploration and Development ("E&D") Costs(1)		50,551		50,551		50,551		223,358		223,358		223,358
Change in Future Development Costs related to E&D		(3,858)		(79,225)		(79,425)		244		46,302		101,360
Total E&D Costs		46,693		(28,674)		(28,874)		223,602		269,660		324,718
Acquisition and Disposition ("A&D") Costs		(60,679)		(60,679)		(60,679)		(49,291)		(49,291)		(49,291)
Change in Future Development Costs related to A&D		(2,483)		(42,923)		(68,210)		(2,483)		(44,616)		(58,011)
Total Acquisition and Disposition ("A&D") Costs		(63,162)		(103,602)		(128,889)		(51,774)		(93,907)		(107,302)
Total Costs		(16,469)		(132,276)		(157,763)		171,829		175,754		217,417
Reserves (mboe)
Total Reserve Discoveries, Extensions & Revisions(2)		3,877		(3,822)		(6,821)		15,376		21,913		29,540
Total Acquisitions and Dispositions		(6,126)		(11,736)		(18,590)		(6,000)		(11,456)		(16,762)
Total Reserve Additions		(2,249)		(15,558)		(25,411)		9,376		10,457		12,778
Finding, Development, Acquisition and Disposition Costs ($/boe)
E&D, including change in FDC related to E&D (F&D)		12.04		7.50		4.23		14.54		12.31		10.99
E&D and A&D, including change in FDC (F,D&A)		7.32		8.50		6.21		18.33		16.81		17.01
Total exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect the total cost of reserve additions in that year.
(1) Unaudited.
(2) Includes extensions and improved recovery, technical revisions, discoveries, and economic factors.

For the Montney program, Delphi achieved F&D costs, including changes in FDC, of $10.12 per boe⁽¹⁾ for proved producing reserves compared to the 2013-15 three year average of $13.41 per boe⁽²⁾. Three year average Montney F&D costs are $11.71 per boe⁽²⁾ and $10.14 per boe⁽²⁾ for total proved and total proved plus probable reserves respectively. Three year average Montney F,D&A costs are $14.79 per boe⁽³⁾, $12.58 per boe⁽³⁾ and $10.62 per boe⁽³⁾ for proved producing, total proved and total proved plus probable reserves respectively. At December 31, 2015, the average gross estimated ultimate recoverable reserves of an extended reach, slickwater stimulated horizontal Montney well is 973 mboe, 900 mboe, 1,212 mboe and 1,065 mboe in the proved producing, total proved, proved plus probable producing and total proved plus probable categories respectively.

One year F&D and F,D&A costs in the total proved and total proved plus probable categories are not meaningful in 2015 as the reduction in future development costs from 2014 to 2015 exceeded actual capital spent and total reserve additions, including technical revisions and economic factors, are also negative.

⁽¹⁾ Capital invested of $46.7 million; change in FDC of -$3.9 million; reserve extensions, improved recovery, technical revisions and economic factors of 4.2 million boe.
⁽²⁾ Capital invested of $213.7 million; change in FDC of $0.6 million, $71.8 million and $147.2 million for proved producing, total proved and total proved plus probable respectively; reserve extensions, improved recovery, technical revisions and economic factors of 16.0 million boe, 24.4 million boe and 35.6 million boe for proved producing, total proved and total proved plus probable respectively.
⁽³⁾ Capital invested of $213.7 million; change in FDC of $0.6 million, $76.8 million and $167.0 million for proved producing, total proved and total proved plus probable respectively; acquisition costs of $22.6 million; reserve extensions, improved recovery, acquisitions, technical revisions and economic factors of 16.0 million boe, 24.9 million boe and 38.0 million boe for proved producing, total proved and total proved plus probable respectively.

Net Asset Value

The estimated net asset value of the Company at December 31, 2015 has been calculated using the before tax, net present value of reserves discounted at five and ten percent as follows:

($ thousands except share count and per share value)		5%		10%
Estimated future net revenues of Proved Plus Probable reserves(1)		390,002		265,151
Undeveloped land(2)		85,205		85,205
Mark-to-market value of hedging contracts(3)		18,461		18,461
In-the-money option proceeds(4)		1,863		1,863
Total asset value		495,531		370,680
Bank debt plus working capital deficiency (unaudited)		(121,664)		(121,664)
Net asset value		373,867		249,016
Common shares outstanding and in-the-money options		157,810,378		157,810,378
Net asset value per share		2.37		1.58
(1) Discounted at five and ten percent and before deducting future income tax expenses. The Company estimates it has approximately $335.7 million of tax deductions available to offset future taxable income.
(2) Undeveloped land was determined by an independent land valuation report by Seaton-Jordan & Associates Ltd. as at December 31, 2015. Fair market value was determined in accordance with NI 51-101 5.9(1)(e).
(3) Financial and physical contracts at December 31, 2015.
(4) In-the-money option proceeds are based on the closing December 31, 2015 share price of $0.89.

Operations Update

Since the end of 2015, Delphi has added another Montney well (0.88 net) to its production base with the 14-27-60-23W5M ("14-27") well that was drilled at the end of 2015. 14-27 was completed in early January utilizing a 37 stage slickwater frac. The well was produced on clean-up over a 3.1 day period recovering approximately 14 percent of the initial load frac water. Over the last 24 hours prior to running production tubing, the well flowed on clean-up at an average rate of 7.2 million cubic feet per day ("mmcf/d") of raw gas and 1,384 barrels per day ("bbls/d") of wellhead condensate (192 bbls/mmcf of raw gas). Total production for the 14-27 well over this 24 hour period was approximately 2,670 barrels of oil equivalent per day ("boe/d"), including an estimated plant natural gas liquids ("NGL") yield of 34 bbls/mmcf of raw gas. 14-27 was brought on production at the beginning of February and is currently producing at a restricted rate of approximately 5.0 mmcf/d of raw gas and 550 bbls/d of wellhead condensate. Initial average production rates over the first 30 days will be reported once the data is available.

The Company has also drilled and completed the 13-21-60-23W5 ("13-21") well (0.66 net). The 13-21 well is the western-most Montney well drilled by Delphi and completed with slickwater fracs. It was drilled to a total depth of 5,690 metres with a horizontal lateral length of 2,781 metres. Delphi continues to optimize its completion techniques, as the 13-21 well was fraced over 37 stages with the largest sand tonnage and slickwater volumes for Delphi Montney wells to date. The 13-21 well was flowed on clean-up over a 2.8 day period, recovering approximately 17 percent of the initial load frac water. Over the last 24 hours prior to running production tubing, the well flowed on clean-up at an average rate of 6.1 mmcf/d of raw gas and 1,872 bbls/d of wellhead condensate (309 bbls/mmcf of raw gas). Total production for the 13-21 well over this 24 hour period was approximately 2,954 boe/d, including an estimated plant NGL yield of 34 bbls/mmcf of raw gas. 13-21 is expected to be brought on production at a restricted rate in March 2016.

Delphi has also commenced drilling of the 15-23-60-23W5 well (1.0 net) and is expected to finish in early March. Completion operations are scheduled after spring break-up conditions allow for access, likely early in the third quarter of 2016.

The Company continues to pursue opportunities to reduce operating costs at its Bigstone property. Delphi estimates $6.0 - $7.0 million in reduced operating costs in 2016 over 2015, as the more efficient Montney production replaces the lower netback properties disposed of in 2015. A new fuel gas pipeline accessing higher quality fuel gas has been installed and the 7-11 compression and dehydration facility has been expanded with an owned compressor replacing two existing rental compressors resulting in reduced maintenance and rental costs as well as increased throughput capacity. In addition, with the disposition of the lower netback properties, the Company has reduced its staff from 36 to 24 (34 percent), resulting in expected general and administrative savings of $2.0 - $2.5 million.

The following table has been updated to reflect new well production data since it was previously released and continues to illustrate the significant impact the slickwater hybrid fracturing technique has had on well performance at Bigstone in comparison to smaller conventional frac methods.

Initial Production (IP) Rate Well Performance ⁽¹⁾

						Number		IP30		IP30		IP30		IP90		IP180		IP270		IP365		IP 2yr
				HZ Length		of Fracs		Total Sales		FCond Rate		Total NGL		Total Sales		Total Sales		Total Sales		Total Sales		Total Sales
		Well(2)										Yield
				(metres)				(boe/d)		(bbls/d)		(bbl/mmcf)		(boe/d)		(boe/d)		(boe/d)		(boe/d)		(boe/d)
Conventional Fracs (original completion technique)
16-30		#1		2,760		20		1,099		273		104		798		558		454		395
05-02		#2		3,005		20		969		170		80		683		479		407		352		253
14-23		#3		2,238		20		1,570		223		70		939		635		532		445		294
Slickwater Fracs (new completion technique)
15-10		#4		1,424		20		991		194		86		842		660		559		482		330
12-17		S.BS Expl(3)		1,848		26		865		199		102		719		554		470		415
Type Well				2,400 - 3,000		30 - 40		1,629		449		119		1,306		1,083		943		843		614
10-27		#5		2,407		30		1,815		582		133		1,667		1,364		1,173		1,019		688
16-23		#6		2,809		30		1,781		465		108		1,502		1,235		1,068		964		708
15-24		#7		2,328		30		1,387		454		136		1,221		1,059		944		853		615
15-30		#8		3,014		30		2,076		566		113		1,837		1,517		1,324		1,164		795
15-21		#9		2,886		30		1,293		499		170		1,053		875		769		689
13-30		#10		2,593		30		2,075		655		136		1,750		1,457		1,268		1,119
02-01		#11		2,807		30		634		209		142		498		422		367		329
02-07		#12		2,702		30		1,116		327		126		940		750		647		570
08-21		#13		2,692		30		978		280		123		870		712		607		529
16-15		#14		2,949		30		1,503		298		91		1,217		1,017		861		749
03-26		#15		2,601		30		1,053		330		134		755		592		506		447
13-23		#16		2,161		30		1,556		400		111		1,282		966		820		717
16-27		#17		2,883		40		1,659		413		108		1,296		1,045		890		761
12-27		#18		2,662		30		1,670		593		154		1,337		1,102		935
16-24		#19		2,802		40		1,182		410		150		929		757
13-24		#20		2,716		40		1,526		469		132		1,172
14-30		#21		2,729		37		1,840		505		118		1,407
14-24(4)		#22		2,602		37		1,119		435		172
14-27		#23		2,887		37
13-21		#24		2,781		37
Average Wells #5 through #22								1,459		438		131		1,220		991		870		762		702
(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries.
(2) Wells numbered chronologically.
(3) Initial Exploration Well on Delphi's South Bigstone Lands.
(4) Production from 14-24 w as restricted during first 29 days of flow.

Risk Management

On December 1, 2015, Delphi began delivering the majority of its natural gas production on its Alliance pipeline firm capacity into the Chicago market rather than the AECO market. Well in advance of commencement of these deliveries, the Company continued execution of its successful risk management strategy to protect its revenue stream into the Chicago market through NYMEX, Chicago basis and US/CDN foreign exchange rate contracts. As a result, the Company is very well hedged through 2016 with approximately 75 percent of its natural gas production hedged at an average price of Cdn. $4.43 per mcf (excluding transportation costs). For 2017, the Company has approximately 50 percent of its natural gas production hedged at an average price of Cdn. $4.24 per mcf (excluding transportation costs). Delphi also has approximately 43 percent of its condensate volumes hedged at a floor price of $76.49 per barrel. The table below summarizes the Company's current commodity price risk management contracts for 2016 and future years.

Natural Gas (Cdn)		2016		2017
Volume (mmcf/d)		2.8		2.4
% Hedged (1)		8%		7%
Hedge Price (Cdn $/mcf) (2)		$3.84		$3.96
Strip Price (Cdn $/mcf)		$1.71		$2.42
Natural Gas (US)		2016		2017		2018		2019
Volume (mmcf/d)		23.5		15.0		5.0		2.0
% Hedged (1)		67%		43%		14%		6%
Hedge Price (US $/mcf)		$3.50		$3.23		$2.79		$2.81
Strip Price (US $/mcf)		$2.07		$2.49		2.57		$2.62
% Hedged in Cdn $ (3)		99%		113%		99%		100%
Hedge Price (Cdn $/mcf) (4)		$4.50		$4.28		$3.70		$4.02
Crude Oil		2016
Volume (bbls/d)		800
% Hedged (1)		43%
Floor Price (WTI Cdn $/bbl)		$78.50
Ceiling Price (WTI Cdn $/bbl) (5)		$85.00
Strip Price (WTI Cdn $/bbl)		$50.66
(1) Percent hedged is based on expected 2016 average natural gas production of 35 mmcf/d and 1,850 bbls/d of condensate and C5+, consistent with guidance.
(2) Before deduction of transportation costs to ship production to AECO on TCPL pipeline.
(3) Percent of US $ hedge value locked in with Cdn/US FX hedges.
(4) Before deduction of transportation costs to ship production to Chicago on Alliance pipeline.
(5) 400 bbls/d have upside to a ceiling price of $85.00 per barrel at a deferred cost of $4.02 per barrel.

Outlook

Delphi continues to navigate this very challenging low commodity price environment with a singular focus on its core Bigstone Montney asset. This focused effort is successfully improving foundational cash generating efficiencies that will be more fully recognized as the rate of capitalization and production growth accelerates into the recovery phase of this commodity price cycle.

Continued innovation of our well design, driving costs lower, while maintaining full ownership and control of our infrastructure are both paramount in our continued effort towards top decile capital and cash generating efficiencies. Generating margin growth trumps production growth in the current environment. The Company's significant hedge position through 2016 and 2017, protects both the equity account and the balance sheet, while contributing to a meaningful capital program of four to five wells in 2016. Delphi's significant drilling inventory is immediately accessible to deliver production growth into a strengthening commodity price environment.

Delphi anticipates releasing its audited financial statements for the year ended December 31, 2015 on March 16, 2016 and its Annual Information Form by March 31, 2015, which will include all required National Instrument 51-101 reserves disclosure.

Certain financial and operating information included in this press release for the quarter and year ended December 31, 2015, such as, but not limited to, finding and development costs, production information, net asset value calculations, are based on unaudited financial results for the year ended December 31, 2015 and are subject to the same limitations as discussed under forward-looking statements outlined at the end of this release. These estimate amounts may change upon completion of the audited financial statements for the year ended December 31, 2015 and those changes may be material.

Delphi Energy is a Calgary-based company that explores, develops and produces oil and natural gas in Western Canada. The Company is managed by a proven technical team. Delphi trades on the Toronto Stock Exchange under the symbol DEE.

Forward-Looking Statements. The release contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events or the Company's future performance and are based upon the Company's internal assumptions and expectations. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance", "budget" and similar expressions.

More particularly and without limitation, this release contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and administrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi's ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations.

Furthermore, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future.

The forward-looking statements and information contained in this release are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the forward-looking statements and information contained in this release are based: the stability of the global and national economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management's expectations, production levels of Delphi being consistent with management's expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management's expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with management's expectations, weather affecting Delphi's ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi's ability to manage environmental risks and hazards and the cos t of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi's ability to market oil and natural gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations.

Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations.

Financial outlook information contained in this release about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this release should not be used for purposes other than for which it is disclosed.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company's operations or financial results are included in the Company's most recent Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this release are made as of the date of this release for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. The forward-looking statements contained in this release are expressly qualified in their entirety by this cautionary statement.

Basis of Presentation. For the purpose of reporting production information, reserves and calculating unit prices and costs, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with the Canadian Securities Administrators' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.

As per CSA Staff Notice 51-327 initial test results and initial production performance should be considered preliminary data and such data is not necessarily indicative of long-term performance or of ultimate recovery.

Non-IFRS Measures. The release contains the terms "funds from operations", "funds from operations per share", "net debt", "operating netbacks" "cash netbacks" and "netbacks" which are not recognized measures under IFRS. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices and costs of production. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-IFRS measure and has been defined by the Company as cash flow from operating activities before accretion on long term and subordinated debt, decommissioning expenditures and changes in non-cash working capital from operating activities. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. Delphi's determination of funds from operations may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Company has defined net debt as the sum of long term debt and subordinated debt plus/minus working capital excluding the current portion of the fair value of financial instruments. Net debt is used by management to monitor remaining availability under its credit facilities. Operating netbacks have been defined as revenue less royalties, transportation and operating costs. Cash netbacks have been defined as operating netbacks less interest and general and administrative costs. Netbacks are generally discussed and presented on a per boe basis.