Seven Generations Announces 2014 Financial and Operating Results and Updated Reserves

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Mar 10, 2015, 22:55 ET

CALGARY, March 10, 2015 /CNW/ - Seven Generations Energy Ltd. ("7G" or the "Company") (TSX: VII) reports its operating and financial results for the fourth quarter of 2014 and year ended December 31, 2014.

"2014 was a fantastic year. Our IPO was successful. We had significant growth of production, reserves and cash flow. We increased our well length, opening the door to improved economics with a reduced environmental footprint. We continued to advance the Kakwa River Project with community and regulatory stakeholders. We raised enough capital with a high yield debt add-on at the beginning of the year and the IPO near the end of the year to enter 2015 with a solid balance sheet, growth rates based on strong well economics and a high degree of financial flexibility leaving us well positioned to weather the recent downturn in oil and gas prices. In 2015, we look forward to continuing to build what we believe will become one of the continent's leading liquids rich gas projects," commented Pat Carlson, CEO.

2014 FOURTH QUARTER AND ANNUAL FINANCIAL AND OPERATING RESULTS

	Three months ended December 31			Year ended December 31
	2014	2013	% Change	2014		2013	% Change
OPERATIONAL
Production
Oil and condensate (bbls/d)	14,747	4,480	229	11,061		2,390	363
NGLs (bbls/d)	10,783	2,291	371	6,989		1,749	300
Natural gas (Mmcf/d)	112	29	286	79		22	259
Oil equivalent (boe/d)	44,178	11,585	281	31,136		7,786	300
Liquids ratio	58%	58%	-	58%		53%	9
Realized prices ⁽³⁾
Oil and condensate ($/bbl)	69.93	80.63	(13)	85.34		85.49	-
NGLs ($/bbl)	21.50	24.54	(12)	24.10		18.76	28
Natural gas ($/mcf)	3.81	3.79	1	4.50		3.34	35
Oil equivalent ($/boe)	38.23	45.49	(16)	47.06		39.83	18
Operating netback per boe ($)⁽¹⁾
Oil and natural gas revenue ⁽³⁾	38.23	45.49	(16)	47.06		39.83	18
Royalties	(3.97)	(2.99)	33	(4.57)		(2.76)	66
Operating expenses	(4.67)	(7.90)	(41)	(4.77)		(7.25)	(34)
Transportation expenses ⁽³⁾	(3.26)	(3.09)	6	(3.06)		(2.28)	34
Netback prior to hedging	26.33	31.51	(16)	34.66		27.54	26
Realized hedging gain	5.45	0.05	10,800	0.86		0.10	760
Netback after hedging	31.78	31.56	-	35.52		27.64	29
General and administrative expenses per boe	1.82	1.93	(6)	1.78		2.86	(38)
FINANCIAL ($000's except per share amounts)
Oil and natural gas revenue ⁽³⁾	155,383	48,484	220	534,833		113,184	373
Funds from operations ⁽¹⁾	101,503	23,114	339	327,933		50,273	552
Per share – diluted ⁽²⁾	0.41	0.12	242	1.46		0.27	440
Operating income ⁽¹⁾	34,815	7,127	388	119,521		5,794	1,963
Per share – diluted ⁽²⁾	0.14	0.04	250	0.53		0.03	1,667
Net income (loss)	68,628	(5,625)	1,320	144,200		(14,158)	1,119
Per share – diluted ⁽²⁾	0.28	(0.03)	1,033	0.64		(0.08)	900
Weighted average shares (#000s) – diluted ⁽²⁾	250,223	192,689	30	224,717		183,288	23
Total capital investments	370,320	178,238	108	1,120,336		574,328	95
Available funding ⁽¹⁾	1,133,800	364,877	211	1,133,800		364,877	211
Net debt ⁽¹⁾	158,270	210,563	(25)	158,270	210,563		(25)
Debt outstanding	813,880	414,525	96	813,880	414,525		96


(1)	Operating netback, funds from operations, operating income, available funding and net debt are not defined under IFRS. See "Non-IFRS Financial Measures" In Management's Discussion and Analysis for the years ended December 31, 2014 and 2013.
(2)	In 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common Voting Shares, stock options and performance warrants on a two-for-one basis. The share split has been reflected for the three months and years ended December 31, 2014 and 2013 on a retroactive basis.
(3)	Certain comparative figures from prior periods have been reclassified to conform to the current year's presentation.

HIGHLIGHTS FOR THE QUARTER AND YEAR ENDED DECEMBER 31, 2014

Fourth quarter 2014 production was 44,178 boe per day representing a 281% increase over fourth quarter 2013 production of 11,585 boe per day. Annual 2014 production averaged 31,136 boe per day compared to 7,786 boe per day during 2013, an increase of 300%.
Liquids ratios for the fourth quarter remained constant at 58% of total production on a boe basis, with fourth quarter condensate production representing 34% of 7G's total production mix.
Seven Generations realized a netback after hedging of $35.52 per boe for the year ended December 31, 2014, compared to $27.64 per boe for the year ended December 31, 2013.
The Company achieved record funds from operations of $327.9 million in 2014 compared to $50.3 million in 2013, an increase of 552%. Funds from operations for the fourth quarter of 2014 was $101.5 million, which was a 339% increase over the fourth quarter 2013.
McDaniel & Associates Consultants Ltd.'s ("McDaniel") estimated total gross proved reserves ("1P") were 420.7 MMboe, as at December 31, 2014, which was an increase of 28% and 292% since the Company's July 1, 2014 and December 31, 2013 reserve evaluations.
McDaniel's estimated total gross proved plus probable reserves ("2P"), as at December 31, 2014, increased to 788.6 MMboe, a 22% increase over the Company's July 1, 2014 gross 2P reserves of 649.1 MMboe and a 178% increase over the December 31, 2013 gross 2P reserves of 283.3 MMboe.
McDaniel's estimated proved developed producing reserves ("PDP") increased to 34.1 MMboe, an increase of 99% over the Company's July 1, 2014 PDP reserves of 17.1 MMboe and a 127% increase over the December 31, 2013 gross PDP reserves of 15.0 MMboe.
Before tax net present values, using a discount rate of 10% per annum, were $3.1 billion for proved reserves and $7.1 billion for proved plus probable reserves, based on McDaniel's estimates as at December 31, 2014.
In the fourth quarter of 2014, the Company closed an initial public offering ("IPO") for net proceeds of $880.1 million through the issuance of 51.8 million class A common shares. During the third quarter of 2014, the Company and its lending syndicate agreed to an amendment to the senior secured revolving credit arrangement that increased the borrowing capacity from $150.0 million to $480.0 million and extended the maturity date of the credit facility to September 2017. As of December 31, 2014, the Company had available funding in excess of $1.1 billion.

OPERATIONAL REVIEW

Fourth quarter production averaged 44,178 boe per day, consisting of 34% condensate and 24% other NGLs, with total liquids representing 58% of total production on a per boe basis. Average annual production for 2014 was 31,136 boe per day, consisting of 58% liquids, with liquids production consisting of 36% condensate and 22% other NGLs on a per boe basis.

Based on preliminary field estimates, production for the first two months of 2015 averaged approximately 47,500 boe per day, on track to achieve 7G's annual production guidance. While production continues to ramp up quite rapidly, growth will be constrained later in the year by the Lator plant capacity until the Lator 2 plant expansion is completed in the fourth quarter of 2015, therefore annual production is expected to be consistent with current guidance of 55,000 to 60,000 boe per day.

An average of 10 drilling rigs were operated during the fourth quarter of 2014, with a peak of 14 rigs operating for most of December. Fourteen wells were rig released in the fourth quarter, including 12 Montney wells in the Nest, 1 Montney well in the Deep Sour region, and 1 First White Specks emerging target well. For the year ended December 31, 2014, the Company drilled 49 gross wells consisting of 44 Montney horizontal wells in the nest, three Montney horizontal delineation wells, one emerging target well and one vertical well. The average horizontal length for the 12 (12.0 net) Montney wells drilled in the Nest in the fourth quarter of 2014 was 2,870 meters with an average spud to rig release time of 56.6 days. Average horizontal lengths drilled per well in 2014 increased 30% over the prior year's average while average drilling days per well was reduced by 18%.

During the fourth quarter of 2014, 7G completed 10 Montney wells in the Nest, and 1 Montney horizontal well in the Wapiti region, stimulating a total of 340 stages, averaging 31 stages per well, 3,800 tonnes of proppant per well, and 1.5 tonnes per meter of lateral. When compared to 7G's 2013 activity, average stages completed per well increased 32% and average tonnes of proppant pumped per well increased 20%. The Company used several completion techniques in the fourth quarter of 2014, including two slickwater fracs, one HiWay frac (a Schlumberger proprietary technique), six nitrogen foam fracs with ball drop sliding sleeve systems, and two nitrogen foam fracs using the plug and perf frac delivery system. Two of the fourth quarter 2014 completions were costlier than expected as a result of having to fish coiled tubing that was stuck downhole during milling operations in one well and the other due to a frac that was initiated in the first quarter of 2014 that was suspended due to access issues and not completed until the fourth quarter of 2014.

The company adjusted our liner design and proppant selection mid fourth quarter, which resulted in decreased completions costs per well. 7G continues to work on optimizing its completion design and has several tests planned for 2015 including experimenting with inter-stage spacing, produced water re-use, proppant selection, higher proppant concentration, and proppant carrying fluid type. The Company intends to apply a standard completion design to approximately 85% of its completions while experimenting, in a controlled fashion, with 15% of its wells. Currently, the Company's standard completion design is comprised of a 28 stage ball-drop system, with nitrogen foam as the carrying fluid for approximately 4,500 tonnes of proppant, resulting in a proppant density of 1.5 tonnes per meter of lateral. These design changes, along with other operational efficiencies are expected to result in substantially improved completion costs in 2015.

	Three months ended		Years ended
	December 31,		December 31,
	2014	2013	2014	2013
Gross Wells Rig Released	14	11	49	23
Average Measured Depth (m)*	6,070	5,280	5,840	5,090
Average Horizontal Length (m)*	2,870	2,200	2,660	2,050
Average Drilling Days per Well*	56	52	54	66
*excludes one abandoned and two vertical wells
Gross Wells Completed	11	9	38	17
Average Number of Stages	31	22	29	22
Average Tonnes Pumped	3,800	2,870	3,330	2,780

During the fourth quarter of 2014, 7G commissioned the Karr 7-11 to Lator condensate pipeline and completed the Lator to Pembina liquids pipeline. The Company anticipates that Pembina will complete its Lator to Fox Creek line looping project in the first quarter of 2015, which will result in reduced condensate transportation costs as the Company shifts from trucking volumes to pipeline connected capacity. Field construction of the 25,000 barrel per day stabilizer at the Karr 7-11 battery also continued in the fourth quarter. The Company expects that the stabilizer will be fully commissioned in the first quarter of 2015, which will help improve condensate quality and reduce pricing discounts.

As of December 31, 2014, the Company had 6 satellite pads and 31 well tie-ins under construction in addition to 9 well tie-ins that were completed in the fourth quarter. 7G currently has an inventory of approximately 47 wells at various stages of construction between drilling and tie-in.

CAPITAL INVESTMENTS

Capital investments totaled $370.3 million for the fourth quarter of 2014 and $1.1 billion for the full year of 2014. 2014 capital invested was approximately 5% over 7G's guidance primarily due to progress payments for long lead items for the Lator 2 and Cutbank area plants, payments associated with a new temporary camp that will be occupied in the first quarter of 2015, earlier than planned drilling of an emerging target well and a deep sour well in addition to higher than expected completion costs.

During the fourth quarter of 2014, 7G invested $227.6 million to drill 14 wells and complete 11 multi-stage horizontal wells with a 100% success rate, with 9 wells brought onto production. For the year ended December 31, 2014, the Company invested $742.0 million to drill 49 wells and complete 38 wells, and brought 34 wells onto production, compared to 23 wells drilled, 17 wells completed and 14 wells brought on production for the year ended December 31, 2013. Drill counts are based on the rig release date and production counts are based on the first reportable production date.

	Three months ended		Years ended
	December 31,		December 31,
	2014	2013	2014	2013
Number of wells drilled – gross	14	11	49	23
Number of wells completed - gross	11	9	38	17
Number of wells brought on production – gross	9	10	34	14
($ thousands)
Drilling	122,493	65,093	391,169	183,375
Completions	105,069	64,138	350,850	138,435
Total Drill and Complete	227,562	129,231	742,019	321,810

In the fourth quarter 2014, the Company invested $132.6 million into facilities and infrastructure. For the year ended December 31, 2014, 7G invested $323.0 million into facilities and infrastructure with 44% invested in pad and well equipment, 42% in major facilities, 8% in pipelines and 6% in supporting infrastructure.

	Three months ended		Year ended
	Dec-31,		Dec-31,
	2014	2013	2014	2013
($ thousands)
Pad and well equipment	51,547	29,921	140,835	54,401
Major facilities	68,385	5,575	135,654	33,585
Pipelines	5,087	3,700	25,489	64,102
Supporting infrastructure	7,591	5,521	21,058	34,606
Facilities and equipment	132,610	44,717	323,035	186,694

FINANCIAL REVIEW

In the fourth quarter of 2014, the Company closed an initial public offering ("IPO") for net proceeds of $880.1 million through the issuance of 51.8 million class A common shares. During the third quarter of 2014, the Company and its lending syndicate agreed to an amendment to the senior secured revolving credit arrangement that increased the borrowing capacity from $150.0 million to $480.0 million and extended the maturity date of the credit facility to September 2017. As of December 31, 2014, the Company had available funding in excess of $1.1 billion.

Despite falling energy prices in the fourth quarter of 2014, 7G generated fourth quarter and full year 2014 funds from operations of $101.5 million and $327.9 million, which were up 339% and 552%, respectively, over comparable 2013 periods. The increase in funds from operations was primarily due to the increase in production volumes that more than offset the lower liquids and gas pricing.

Fourth quarter and full year 2014 netbacks prior to hedging averaged $26.33 per boe and $34.66 per boe, which were 16% lower and 26% higher than similar periods in 2013, respectively. After hedging, 7G's fourth quarter and annual 2014 netbacks were $31.78 per boe and $35.52 per boe, which were equivalent to and 29% higher than comparable periods in 2013.

As of December 31, 2014, 7G had approximately 68,500 GJ/d of 2015 AECO exposed production hedged at an average price of $3.85/GJ and average 8,200 barrel per day of 2015 liquids production hedged at a WTI price of approximately $101.80 CAD per barrel.

MARKETING

During the fourth quarter of 2014, 7G converted the portion of its outstanding Alliance pipeline commitments that had initially been contracted as firm receipt service to firm full path service and extended the expiry on all outstanding Alliance pipeline commitments to 2022. The conversion in service means that, as of December 2015, all of the Company's gas delivered onto the Alliance Pipeline will be transported to Chicago and will have access to US Midwest markets.

The Company's average realized price for condensate and oil in the fourth quarter of 2014 was $69.93 per barrel, which was an approximate $10 per barrel discount to the Alberta benchmark CRW condensate price. Condensate pricing is expected to improve and trade closer to Alberta benchmark pricing as the Company commissions its condensate stabilizer in the first quarter of 2015, which is expected to improve the quality of marketed product.

The average realized prices for NGLs primarily reflect a combination of prices for NGLs such as ethane, propane, butane and pentanes plus. The Company's average realized prices decreased for this product stream in the fourth quarter of 2014 by 12% to $21.50 per barrel, compared to $24.54 per barrel for the same period in 2013. For the 2014 year end, the Company realized average prices of $24.10 per barrel for its NGLs as compared to $18.76 per barrel for the comparative period in 2013, an increase of 28%.

The Company's average realized natural gas price increased by 1% to $3.81 per mcf for the fourth quarter of 2014, compared to $3.79 per mcf in the same period in 2013. For the year ended December 31, 2014, the Company's average realized natural gas price increased by 35% to $4.50 per mcf compared to $3.34 per mcf in 2013. The Company receives a blend of pricing based on AECO monthly and daily benchmark indexes.

LAND UPDATE

Since the Company's last land update during the third quarter of 2014, 7G has increased its land holdings by 76,480 (gross and net) acres at an average cost of $117 per acre. As of December 31, 2014, the Company held more than 424,000 net acres with Montney rights on 407,475 net acres with an average working interest of 98%. During the fourth quarter of 2014 the Company acquired approximately 68,800 acres at a total cost of $8.2 million.

OUTLOOK

On February 24, 2015, the Company announced its plan to reduce 2015 capital investments downwards by $250 - $300 million, resulting in a revised capital program of $1.30 to $1.35 billion. The Company plans to defer spending of approximately $200 to $250 million and also expects, through negotiations with suppliers and business partners, to capture additional cost savings on 2015 projects of at least $50 million, resulting in an aggregate capital investment reduction of approximately 15% to 20% from the earlier announced budget of $1.60 billion.

The Company anticipates 2015 production to be between 55,000 and 60,000 boe per day and plans to drill 77 new wells in 2015 with 60 new producing wells coming on line in 2015. Currently 7G has initiated but not completed work on an in-process inventory of 47 new wells that will help fuel the Company's production growth. 7G's operated drilling rig count is currently 10 and is expected to ramp up to 13 rigs at mid-year and to 15 rigs for the last two months of 2015.

In 2015, 7G plans to finish the expansion of its Lator refrigeration plant to its 250 MMcf/d rich gas sales capacity and to initiate the construction of a second refrigeration plant which, when complete in 2016, will increase processing capacity to 500 MMcf/d and allow the Company to continue to profitably deliver rich gas volumes into its firm transportation commitments.

RESERVES

7G's independent reserves evaluation, effective December 31, 2014, was recently completed by McDaniel & Associates Consultants Ltd. ("McDaniel"). McDaniel prepared the evaluation in compliance with the standards set out in National Instrument 51-101 of the Canadian Securities Administrators and the Canadian Oil and Gas Evaluation Handbook. For additional information regarding the independent reserves evaluation that was conducted by McDaniel, as at December 31, 2014, please see the disclosure that is provided under the heading "Independent Reserves Evaluation" below and the Company's Annual Information Form dated March 10, 2015 ("AIF"), which is available on the SEDAR website at www.sedar.com.

Total gross 1P reserves of 420.7 MMboe, as at December 31, 2014, represented an increase of 28% and 292% when compared to the Company's July 1, 2014 and December 31, 2013 gross 1P reserves of 328.0 MMboe and 107.2 MMboe, respectively.
Total gross 2P reserves, as at December 31, 2014, were 788.6 MMboe, a 22% increase over the Company's July 1, 2014 gross 2P reserves of 649.1 MMboe, and a 179% increase over the Company's December 31, 2013 gross 2P reserves of 283.3 MMboe.
PDP reserves increased to 34.1 MMboe as at December 31, 2014, an increase of 99% over the Company's July 1, 2014 PDP reserves of 17.1 MMboe.Before tax net present values, using a discount rate of 10% per annum, were $3.1 billion for gross 1P reserves and $7.1 billion for gross 2P reserves, as of December 31, 2014.
2014 finding and development ("F&D") costs, including future development capital, were $14.09 per boe for gross 2P reserves and $17.76 per boe for gross 1P reserves.
The Company had a recycle ratio of 2.46 times for gross 2P reserves evaluated as at December 31, 2014, based on the aforementioned F&D costs and pre-hedging netbacks of $34.66 per boe, as at December 31, 2014.

The tables below summarize data contained in the independent reserves evaluation report that was prepared by McDaniel, as at December 31, 2014, and may contain slightly different numbers than that report due to rounding. Also, certain columns may not add as a result of rounding.

Summary of Reserves as at December 31, 2014


	LIGHT AND MEDIUM		NATURAL GAS		NGLs		TOTAL
	CRUDE OIL		NATURAL GAS		NGLs		TOTAL
RESERVES CATEGORY	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(Mboe)	(Mboe)
PROVED:
Developed Producing	21	19	98,895	89,267	17,632	15,387	34,135	30,283
Developed Non-Producing	-	-	13,829	12,870	2,525	2,253	4,830	4,398
Undeveloped	-	-	1,075,679	996,528	202,418	180,401	381,697	346,489
TOTAL PROVED⁽¹⁾	21	19	1,188,402	1,098,664	222,574	198,041	420,663	381,170
TOTAL PROBABLE	9	8	1,018,163	888,613	198,266	163,724	367,969	311,834
TOTAL PROVED PLUS PROBABLE⁽¹⁾	30	26	2,206,565	1,987,278	420,840	361,765	788,631	693,004

(1)

These figures are derived from volumes that are arithmetic sums of multiple estimates of reserves categories or sub-categories, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should review the estimates of individual classes of reserves and appreciate the differing probabilities of recovery associated with each class as explained above under the heading "Presentation of Oil and Gas Reserves and Resources and Production Information" in the AIF which is available on the SEDAR website at www.sedar.com.

Summary of Before Tax Net Present Values as of December 31, 2014


	Discount Rate
	0%	5%	10%	15%	20%
RESERVES CATEGORY	($MM)	($MM)	($MM)	($MM)	($MM)
PROVED:
Developed Producing	688	609	550	504	467
Developed Non-Producing	101	88	77	69	63
Undeveloped	5,964	3,840	2,518	1,652	1,061
TOTAL PROVED⁽¹⁾	6,753	4,537	3,145	2,225	1,591
TOTAL PROBABLE	9,189	5,784	3,963	2,896	2,223
TOTAL PROVED PLUS PROBABLE⁽¹⁾	15,942	10,321	7,108	5,121	3,815

(1)

Summary of After Tax Net Present Values as of December 31, 2014 Forecast Prices and Costs


	Discount Rate
	0%	5%	10%	15%	20%
RESERVES CATEGORY	($MM)	($MM)	($MM)	($MM)	($MM)
PROVED:
Developed Producing	688	609	550	504	467
Developed Non-Producing	101	88	77	69	63
Undeveloped	4,712	2,944	1,842	1,123	637
TOTAL PROVED⁽¹⁾	5,501	3,641	2,469	1,697	1,167
TOTAL PROBABLE	6,891	4,288	2,906	2,106	1,609
TOTAL PROVED PLUS PROBABLE⁽¹⁾	12,392	7,928	5,376	3,803	2,776

(1)

Reconciliation of Gross Reserves


	Light and Medium Crude Oil			NGLs
Factors	Gross	Gross	Gross	Gross	Gross	Gross
	Proved	Probable	Proved	Proved	Probable	Proved
			Plus			Plus
			Probable			Probable
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
December 31, 2013	50	18	68	52,425	91,630	144,055
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	5	-	5	119,481	142,396	261,877
Technical Revisions	-23	-9	-33	57,243	-35,760	21,482
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-
Production	-11	-	-11	-6,574	-	-6,574
December 31, 2014	21	9	30	222,574	198,266	420,840

Reconciliation of Gross Reserves (continued)


	Total Natural Gas			Total Boe
Factors	Gross	Gross	Gross	Gross	Gross	Gross
	Proved	Probable	Proved	Proved	Probable	Proved
			Plus			Plus
			Probable			Probable
	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
December 31, 2013	328,496	506,284	834,780	107,224	176,029	283,253
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	695,876	783,282	1,479,159	235,466	272,943	508,409
Technical Revisions	192,654	-271,404	-78,749	89,328	-81,003	8,325
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-
Production	-28,624	-	-28,624	-11,355	-	-11,355
December 31, 2014	1,188,402	1,018,163	2,206,565	420,663	367,969	788,631

Future Development Costs

The following table sets forth development costs deducted in the estimation of the Company's future net revenue attributable to the reserves categories noted below:


	ANNUAL DEVELOPMENT COSTS
Year	Total Proved	Total Proved Plus Probable
	($MM)	($MM)
2015	1,019	1,019
2016	1,339	1,339
2017	1,399	1,409
2018	1,310	1,311
2019	1,058	1,058
Thereafter	7	2,756
Total (Undiscounted)	6,132	8,892

For important additional information regarding the independent reserves evaluations that were conducted by McDaniel, see the disclosure that is provided under the heading "Independent Reserves Evaluation" below and the Company's AIF, which is available on the SEDAR website at www.sedar.com. The Company has commissioned McDaniel to prepare a year-end resource report, which the Company expects will be completed during the second quarter of 2015.

7G's Audited Financial Statement and Notes, Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2014 are available at www.7genergy.com and www.sedar.com.

CONFERENCE CALL

7G management plans to hold a conference call to discuss results and address investor questions on Wednesday, March 11, 2015 at 9:00 a.m. MDT (11:00 a.m. EDT).

Dial in:	(587) 880 2171 (Calgary)

	(416) 764 8688 (Toronto)

	(888) 390 0546 (Toll Free)

Replay:	(888) 390 0541 (available until April 8, 2015)

Replay code: 086999#

Reader Advisory

This document contains certain forward-looking information and statements that involves various risks, uncertainties and other factors. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "should", "believe", "plans", and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this document contains forward-looking information and statements pertaining to the following: anticipated production and production guidance; the expected timing and completion of: the Lator 2 plant expansion, the Pembina Lator to Fox Creek pipeline, the 25,000 bbl/d stabilizer at the Karr 7-11 battery and the expected benefits to the derived therefrom; the expected timing of the completion and occupation of a temporary camp being set up by the Company; expectations for the transportation of the Company's products; plans to defer spending; anticipated future cost savings; plans regarding the number of wells to be drilled and the number of wells expected to come on production in 2015; and expectations for future production growth. In addition, references to reserves are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated.

With respect to forward-looking information contained in this document, assumptions have been made regarding, among other things: future oil, natural gas liquids and natural gas prices; the Company's ability to obtain qualified staff and equipment in a timely and cost efficient manner; the Company's ability to market production of oil, NGLs and natural gas successfully to customers; the Company's future production levels; the applicability of technologies for the Company's reserves; future capital investments by the Company; future cash flows from production; future sources of funding for the Company's capital program; the Company's future debt levels; geological and engineering estimates in respect of the Company's reserves, the geography of the areas in which the Company is conducting exploration and development activities, and the access, economic and physical limitations to which the Company may be subject from time to time; the impact of competition on the Company; and the Company's ability to obtain financing on acceptable terms.

Actual results could differ materially from those anticipated in this forward-looking information as a result of the risks and risk factors that are set forth in the AIF, which is available on SEDAR at www.sedar.com, including, but not limited to: volatility in market prices and demand for oil, natural gas liquids and natural gas and hedging activities related thereto; general economic, business and industry conditions; variance of the Company's actual capital costs, operating costs and economic returns from those anticipated; risks related to the exploration, development, production and transportation of oil and natural gas reserves and resources; negative public perception of oil sands development, oil and natural gas development and transportation, hydraulic fracturing and fossil fuels; actions by governmental authorities, including changes in government regulation, royalties and taxation; the management of the Company's growth; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; the absence or loss of key employees; uncertainty associated with estimates of oil, natural gas liquids and natural gas reserves and the variance of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the Company does not control; shortage or lack of available pipeline capacity or other transportation facilities; the ability to satisfy obligations under the Company's firm commitment transportation arrangements; uncertainties related to the Company's identified drilling locations; the concentration of the Company's assets in the Kakwa area; unforeseen title defects; First Nations claims; failure to accurately estimate abandonment and reclamation costs; changes in the interpretation and enforcement of applicable laws and regulations; terrorist attacks or armed conflicts; reassessment by taxing authorities of the Company's prior transactions and filings; variations in foreign exchange rates and interest rates; third-party credit risk including risk associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential for litigation; variation in future calculations of non-IFRS measures; sufficiency of internal controls; impact of expansion into new activities on risk exposure; risks related to the senior unsecured notes and other indebtedness, including: potential inability to comply the covenants in the credit agreement related to the Company's credit facilities and/or the covenants in the indenture in respect of the senior secured notes; seasonality of the Company's activities and the Canadian oil and gas industry; and extensive competition in the Company's industry.

The forward-looking information and statements contained in this document speak only as of the date hereof, and the Company does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Independent Reserves Evaluation

Estimates of the Company's reserves and the net present value of future net revenue attributable to the Company's reserves: (i) as at December 31, 2014, are based upon the report that was prepared by McDaniel, evaluating the Company's oil, natural gas and NGL reserves, dated February 19, 2015; (ii) as at July 1, 2014, are based upon the report that was prepared by McDaniel, evaluating the Company's oil, natural gas and NGL reserves, dated July 23, 2014; and, as at December 31, 2013, are based upon the report that was prepared by McDaniel, evaluating the Company's oil, natural gas and NGL reserves, dated February 24, 2014. The estimates of reserves provided in this document are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided in this in this document, and the difference may be material. Estimates of net present value of future net revenue attributable to the Company's reserves do not represent fair market value of the Company's reserves. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluating the Company's reserves will be attained and variances could be material. For important additional information regarding the independent reserves evaluations that were conducted by McDaniel, please refer to the AIF and to the Company's Supplemented PREP Prospectus dated October 29, 2014, which are available on the SEDAR website at www.sedar.com.

Finding and development costs have been calculated for proven reserves by taking the sum of: (i) exploration costs; (ii) development costs; and (iii) the change in estimated future development costs relating to proved reserves during the year; divided by the additions to proved reserves during the year. Finding and development costs for proved plus probable reserves have been calculated by taking the sum of: (i) exploration costs, (ii) development costs and (iii) the change in estimated future development costs during the year and dividing by: (iv) the additions to proved plus probable reserves during the year. Comparative information for 2013 and the average of the three most recent years has not been provided for finding and development costs as no independent reserve reports were prepared for the Company as at December 31, 2012 or 2011. The aggregate of the 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 total finding and development costs related to reserves additions for that year.

Oil and Gas Definitions

developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

gross means:

in relation to the Company's interest in production or reserves, its "company gross reserves", which are the Company's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company;
in relation to wells, the total number of wells in which a company has an interest; and
in relation to properties, the total area of properties in which a company has an interest.

net means:

in relation to the Company's interest in production or reserves, the Company's working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company's royalty interest in production or reserves;
in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and
in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company.

probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates

undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved or probable) to which they are assigned.

Abbreviations

AECO	physical storage and trading hub for natural gas on the TransCanada Alberta transmission system which is the delivery point for various benchmark Alberta index prices
bbl	barrel or barrels
bbls/d	barrels per day
boe	barrels of oil equivalent
boe/d	barrels of oil equivalent per day
C5+	pentanes plus
GJ	gigajoules
GJ/d	gigajoules per day
m	meter
mcf	million cubic feet
Mmcf/d	million cubic feet per day
MMboe	millions of barrels of oil equivalent
NGLs	natural gas liquids
WTI	West Texas Intermediate
$ or CAD	Canadian dollars
$MM	millions of dollars

(1)

Seven Generations has adopted the standard of 6 Mcf:1 bbl when converting natural gas to oil equivalent. Condensate and other NGLs are converted to oil equivalent at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based roughly on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the Company's sales point. Given the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.

SOURCE Seven Generations Energy Ltd.

Image with caption: "Seven Generations Energy Ltd. (CNW Group/Seven Generations Energy Ltd.)". Image available at: http://photos.newswire.ca/images/download/20150310_C5452_PHOTO_EN_13052.jpg

Pat Carlson, CEO; Chris Law, Vice President Corporate Planning; Brian Newmarch, Manager Investor Relations; Seven Generations Energy Ltd., Suite 300, 140 - 8th Avenue SW, Calgary, AB, T2P 1B3, Phone: 403-718-0700, Email: [email protected]

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