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Seven Generations Energy's First Quarter Cash Flow up 60 Percent

May 04, 2015

Production increases 141 percent to 48,800 boe/d; drilling and completion costs improving


Seven Generations Energy Ltd. (7G or the Company) generated a 60 percent increase in cash flow and a 141 percent increase in production in the first quarter, as compared to the same period of 2014.

"Our financial and operating performance during our first full quarter as a public company provides additional testament to how our low-cost production and field optimization provides us with the competitive edge to sustainably grow Seven Generations, even during this period of significantly lower energy prices," said Pat Carlson, 7G's Chief Executive Officer.

"With our first quarter na tural gas production averaging 125 Mmcf/d, and construction now underway on our Lator 2 gas processing plant, we are on track to deliver 250 Mmcf/d of liquids-rich natural gas to the Chicago-area market on the Alliance Pipeline at the end of 2015. As Canadian energy producers continue to look for expanded market access, the value of a liquids-rich pipeline out of an oversupplied region continues to prove its worth," Carlson said.

"We continue to operate from a position of financial strength with the recent issue of US$425 million of senior notes and an increase to our undrawn credit facility up to $650 million. This takes our available funding, including adjusted working capital at the end of the first quarter, to more than $1.5 billion. As 2015 funds from operations are expected to grow in line with rising production, we are very well positioned to fund our low-cost growth through 2016 while maintaining manageable debt levels, backed by a strong commodity hedge position," Carlson added.


  • Strong production growth with first quarter 2015 production averaging 48,768 boe/d consisting of 57 percent liquids. First quarter 2015 production increased 10 percent from the fourth quarter of 2014 and is up 141 percent compared to the first quarter of 2014.
  • Successful implementation of standardized well construction design with the most recent five Super Pad wells resulting in drilling and completion costs of less than $13 million per well.
  • 7G commissioned a 25,000 boe/d condensate stabilizer in March 2015, which is expected to improve condensate quality and pricing in future quarters.
  • Subsequent to quarter-end, 7G issued US$425 million of senior notes due in 2023 with a coupon of 6.75 percent. Additionally the Company and its lending syndicate have agreed to increase the size of its undrawn senior secured revolving credit facilities from $480 million to $650 million. On a pro forma basis, 7G has available funding in excess of $1.5 billion as at March 31, 2015.
  • Effective resource growth and resource-to-reserve conversion. In its report dated March 31, 2015, McDaniel & Associates Consultants Ltd. (McDaniel) assigned Best Estimate Contingent Resources of 905 MMboe to the Company's properties as at December 31, 2014, an increase of approximately 24 percent compared to the prior evaluation dated July 1, 2014. Best Estimate Contingent Resources increased approximately 177 MMboe, outpacing the 140 MMboe growth in proved plus probable reserves over the same time period.
  • 7G continues to actively hedge production with an average of 65,000 MMBtu/d of 2015 AECO gas hedged at an average price of $4.07/MMBtu and an average of 54,000 MMBtu/d of 2016 volumes hedged at approximately $4.00/MMBtu. The Company has on average 9,500 barrels per day of 2015 liquids hedged at a minimum WTI price of $96.10 per barrel and 11,000 barrels per day of 2016 liquids hedged with $70.00 - $80.80 collars.


  Three months ended March 31
      2015   2014   % Change
Oil and condensate (bbls/d) 15,810 7,554 109
NGLs (bbls/d) 12,042 4,054 197
Natural gas (Mmcf/d) 125 52 140
Oil equivalent (boe/d) 48,768 20,231 141
Liquids ratio 57% 57% -
Realized prices
Oil and condensate ($/bbl) 47.59 92.61 (49)
NGLs ($/bbl) 8.69 28.25 (69)
Natural gas ($/mcf) 2.78 5.47 (49)
Oil equivalent ($/boe) 24.73 54.23 (54)
Oil and natural gas revenue 108,540 98,737 10
Funds from operations (1) 86,889 54,164 60
Per share – diluted 0.32 0.25 28
Operating income (1) 23,998 24,481 (2)
Per share – diluted 0.09 0.12 (25)
Net income (loss) (82,698) 1,164 (7,205)
Per share – diluted (0.34) 0.01 (3,500)
Weighted average shares (#000s) – diluted 270,792 212,034 6
Total capital investments 368,400 200,549 84
Available funding (1) 861,385 574,581 50
Net debt (1) 505,234 349,269 45
Debt outstanding       888,356   775,809   15
(1) 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 three months ended March 31, 2015 and 2014 which is available on SEDAR at


First quarter 2015 production averaged 48,768 boe/d consisting of 57 percent liquids (32 percent condensate and 25 percent NGLs), which is a 10 percent increase in production over the fourth quarter of 2014 volumes and a 141 percent increase from first quarter 2014. Annual average production guidance for 2015 is unchanged at 55,000 to 60,000 boe/d. Production from 7G's core liquids-rich gas field – the Nest – continues to meet expectations. Newer wells are showing slightly higher liquids yields than originally anticipated. This is attributed to longer laterals, higher proppant densities, and restricted production rates, which optimizes recoveries in a manner that 7G refers to as "slowback".

Capital investments totaled $368 million in the first quarter, which reflects the higher planned activity in the first and fourth quarters of 2015. About 71 percent of first quarter capital was invested in drilling and completions and 28 percent in facilities and well equipment. First quarter capital investments included the drilling of 23 gross (22.5 net) wells and the completion of 17 gross ( 16.5 net) wells, with a 100 percent success rate. 7G's 2015 capital program remains consistent with previous guidance of $1.3 billion to $1.35 billion.


Three months ended March 31,
2015 2014
Gross Hz Wells Rig Released 23 9
Average Measured Depth (m) 5,901 5,484
Average Horizontal Length (m) 2,717 2,350
Average Drilling Days per Well 51 54
Gross Wells Completed 17 6
Average Number of Stages 30 23.5
Average Tonnes Pumped 4,200 2,550

An average of 11 drilling rigs were operated during the first quarter of 2015, with the rig count reduced from a peak of 14 in January (13 operated and 1 non-operated) to nine operated rigs at the end of the quarter. All first quarte r 2015 drilling targeted the Montney formation and included two wells which were cored through the Montney, then plugged back and drilled laterally. During the first quarter, 7G rig released one (1.0 net) deep SW well, one (1.0 net) Lower Montney well, one (0.5 net) non-operated Wapiti area well, and 20 (20.0 net) Upper/Middle Montney wells in the Nest area. The average horizontal length for the 20 (20.0 net) Upper/Middle Montney wells drilled in the Nest in the first quarter was 2,756 meters with an average spud to rig release time of 51 days and an average drilling cost of $6.1 million. Market conditions and the stability of 7G's development program enabled the Company to replace some less efficient rigs with some of the most modern and efficient drilling equipment available for pad-style Nest area drilling.

During the first quarter, 7G completed 16 wells in the Nest, stimulating a total of 488 stages, averaging 30 stages and 4,200 tonnes (9.2 million pounds) per well, for an average completion cost of approximately $7.6 million. First quarter completion costs were approximately 35 percent below fourth quarter 2014 costs, reflecting design optimizations and reduced service costs. Optimization efforts have been focused on reducing coil tubing interventions, reduced-cost proppant selection, and more efficient pressure pumping operations. 7G's last five Super Pad wells, with an average lateral length of 3,042 meters, had average well construction costs (drilling and completion) of less than $13 million using the standardized well construction design. Performance of the dedicated Schlumberger hydraulic fracturing spread has been strong and has delivered operational and efficiency gains. As a result, effective March 7, 2015, both parties agreed to extend the term of the pressure pumping contract through March 2016 in exchange for further pricing improvements.

The 25,000 barrel per day stabilizer at the Karr 7-11 battery was commissioned at the end of the first quarter and is expected to improve condensate quality and reduce pricing discounts in subsequent quarters. During the first quarter, construction began on the Lator 2 gas plant expansion and the project is on schedule for a November 2015 commissioning and a December 1, 2015 start-up, consistent with the commencement of the 250 MMcf/d Alliance and Aux Sable transportation and extraction commitment. The Lator 2 gas plant expansion is expected to cost about $155 million, of which approximately 34 percent was invested by the end of the first quarter of 2015. Subsequent to the end of the quarter, regulatory approvals were received for the next 250 MMcf/d plant, tentatively named Cutbank, and clearing of the plant site began on April 15. The Cutbank plant, meter station and pipeline connecting to the Company's gathering system are expected to cost about $233 million, of which 16 percent ($37 million) was invested by the end of the first quarter. Start-up of the Cutbank plant is scheduled for mid-2016.

As of March 31, 2015, the Company had 5 satellite pads and 17 well tie-ins under construction in addition to 19 well tie-ins that were completed in the first quarter. The Company currently has an inventory of approximately 45 wells at various stages of construction between drilling and tie-in.


7G continues to be in a strong financial position with more than $860 million of available funding as of March 31, 2015, which consists of $380 million of adjusted workin g capital plus an undrawn $480 million revolver. Subsequent to quarter-end, 7G announced the issuance of US$425 million senior unsecured 6.75 percent notes maturing in 2023. In addition, the Company and its lenders have increased the size of the senior secured revolving credit agreement from $480 million to $650 million. On a pro forma basis, 7G has available funding in excess of $1.5 billion as of March 31, 2015.

The Company generated funds from operations of $87 million for the quarter ended March 31, 2015. Benchmark WTI and AECO natural gas prices were 51 percent lower than the first quarter of 2014. 7G's increased production offset the lower energy price environment equating to a 60 percent year-over-year increase in funds from operations.

Netbacks for the first quarter of 2015 were $13.43 per boe before hedging and $24.97 per boe after hedging. First quarter 2015 netbacks were adversely impacted by lower realized condensate and natural gas pricing, coupled with higher royalties. In the first quarter of 2015, the Company trucked condensate and NGLs to a number of delivery points, partially due to restricted liquids pipeline access, which resulted in lower realized condensate prices when compared to benchmark prices. Additionally, the Company did not have its condensate stabilizer operational until late in the quarter and did not realize the benefits associated with stabilization. The Company anticipates being able to ship a portion of its volumes for the remainder of 2015 under its firm liquids transportation commitment, which commenced on May 1, 2015. Condensate volumes in excess of the Company's fir m transportation commitments are anticipated to have higher transportation charges and lower realizations compared to pipeline connected volumes.

7G's realized natural gas price was impacted by a seasonal widening of the pricing differential between AECO and Chicago Citygate gas markets. Under the Company's Aux Sable extraction agreement, 7G is required to purchase make-up gas to replace the heat value removed during the NGL extraction process. Make-up gas purchases are priced off the Chicago Citygate market and netted against the Company's AECO based revenues resulting in a negative impact to the net realized price. 7G will be exposed to these market price differentials until December 2015, at which point the Company's long-haul Alliance Pipeline transportation agreement begins. The Company also experienced higher royalty costs on a per boe basis due to timing differences in its royalty payments. The Company does not anticipate royalties to remain in this range and expects to see royalties in line with the 2014 annual average of 10 percent to 12 percent of revenue.


  Three months ended March 31
Operating netback per boe ($) (1)       2015 2014 percent
Oil and natural gas revenue     24.73 54.23 (54)
Royalties (3.46) (2.96) 17
Operating expenses (4.89) (6.26) (22)
Transportation expenses    


(2.95) (3.64) (19)
Netback prior to hedging 13.43 41.37 (68)
Realized hedging gain (loss)       11.54 (2.97) 489
Netback after hedging       24.97 38.40 (35)
General and administrative expenses per boe 1.52 1.74 (13)
(1) Operating netback is not defined under IFRS. See "Non-IFRS Financial Measures" in Management's Discussion and Analysis for the three months ended March 31, 2015 and 2014 which is available on SEDAR at


Risk management continues to be an important component of 7G's financial strategy. Management has set an internal hedge target of up to 55 percent of forecasted production volumes (net of royalties) for the upcoming four quarters and up to 30 percent of forecasted production volumes (net of royalties) for the successive four quarters. Price targets are established at levels that will provide a threshold rate of retu rn on capital investment based on a combination of benchmark oil and gas prices, projected well performance and capital efficiencies. As of the date of this news release, the Company had an average of 65,000 MMBtu/d of 2015 AECO gas hedged at an average price of $4.07/MMBtu and an average of 54,000 MMBtu/d of 2016 volumes hedged at approximately $4.00/MMBtu. The Company has on average 9,500 barrels per day of 2015 liquids hedged at a minimum WTI price of $96.10 per barrel and 11,000 barrels per day of 2016 liquids hedged with $70.00 - $80.80collars.


Based upon the independent evaluation that was conducted by McDaniel, as at December 31, 2014, the Contingent Resources (Best Estimate) attributable to the Kakwa River Project, increased by approximately 24 percent compared to McDaniel's previous evaluation that was conducted as at July 1, 2014. This adds to 7G's significant inventory of low-cost liquids and natural gas development opportunities.

For additional information about 7G's Best Estimate Contingent Resources, as evaluated by McDaniel, please see Schedule "A".

Conference Call

7G management plans to hold a conference call to discuss results and address investor questions on Tuesday, May 5, 2015 at 9:00 a.m. MDT (11 a.m. EDT).

Dial in:   (587) 880 2171 (Calgary)
(416) 764 8688 (Toronto)
(888) 390 0546 (Toll Free)
Replay: (888) 390 0541 (available until June 2, 2015)
Replay code: 612538#

About the Company

Seven Generations Energy Ltd. is an Alberta-based company engaged in the development of the Kakwa River Project (the Project). Located approximately 100 kilometres south of Grande Prairie, Alberta, the Project is a tight, liquids-rich gas and light oil project in the early stages of development. 7G has its corporate headquarters in Calgary, Alberta and its operations headquarters in Grande Prairie, Alberta.

Reader Advisory

This press release 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 press release contains forward-looking information and statemen ts pertaining to the following: anticipated production, production growth and production guidance; ability to fulfill future firm transportation and marketing commitments; the expectation that current sources of funding will finance low cost growth through 2016; future debt levels and hedge postions; and the anticipated improvement of condensate quality and reduction of pricing discounts expected as a result of the commissioning of a condensate stabilizer at the Karr 7-11 battery; and the expected cost of the Lator 2 gas plant expansion and the Cutbank plant, meter station and pipelined to the Company's gathering system. In addition, references to Contingent Resources and reserves are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the Contingent Resources and reserves described exist in the quantities predicted or estimated. This includes the number of undeveloped drilling locations and the timing of the development of the undeveloped properties with attributed Contingent Resources, the recovery technologies to be utilized, the anticipated future volumes of sales gas to be produced, and the total future costs associated with the development of the properties with attributed Contingent Resources.

With respect to forward-looking information contained in this press release, 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 Compa ny's reserves and Contingent Resources, 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 Company's Annual Information Form, dated March 10, 2015, which is available on SEDAR at, 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 and production 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 Contingent Resources 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; the ability to satisfy obligations under the Company's firm commitment transportation arrangements; uncertainties related to the Company's id entified 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 with the covenants in the credit agreement related to the Company's credit facilities and/or the covenants in the indentures in respect of the Company's 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 press release 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.

Certain Oil and Gas Definitions

gross in relation to wells, means the total number of wells in which a company has an interest.

net in relation to the Company's interest in wells, means the number of wells obtained by aggregating the Company's working interest in each of its gross wells.

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


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 (1)
boe/d barrels of oil equivalent per day
Hz horizontal
m metre
mcf million cubic feet
Mmcf/d million cubic feet per day
MMboe millions of barrels of oil equivalent
MMBtu million British thermal units
NGLs natural gas liquids
US$ United States dollars
WTI West Texas Intermediate
$ Canadian dollars
$MM millions of dollars
(1) 7G 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 7G'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.

Schedule "A"

In the report of McDaniel & Associates Consultants Ltd. ("McDaniel"), the independent reserves evaluator of Seven Generations Energy Ltd. ("7G" or the "Company") dated March 31, 2015, evaluating the oil, natural gas and NGL Contingent Resources (as defined below) attributable to certain of the Company's assets as at December 31, 2014 (the "McDaniel Resources Report"), McDaniel assigned Contingent Resources (Best Estimate) (as defined below) of 905 MMboe to the Company's Kakwa River Project. The Contingent Resources estimate is based upon an undeveloped drilling inventory of 1087 wells, assuming development over an 11 year drilling period, beginning with the first wells drilled in 2020 and the last wells drilled in 2031. Capital spending for the required additional facilities and infrastructure is expected to commence in 2017. Of the 1087 undeveloped wells, 85% are upper and middle Montney horizontal wells and 15% are Cadotte horizontal wells. McDaniel has estimated that the total cost required to achieve commercial production in respect of the undeveloped drilling inventory is approximately $13.78 billion. These locations are anticipated in the McDaniel Resources Report to add an incremental 250 MMcf/d of sales natural gas in addition to the 550 MMcf/d of sales natural gas generated from proved and probable reserves, as evaluated by McDaniel at December 31, 2014.

The table below summarizes the Contingent Resources (Best Estimate) values based on the McDaniel Resources Report:

  Net Present Values of Future Net Revenue
as of December 31, 2014
Discounted at (%/Year)
Contingent Resources — Best Estimate (2)(3)(4)(5)
Gross (1)   0%   5%   10%   15%   20%
(MMboe) (MM$) (MM$) (MM$) (MM$) (MM$)
Before Income Taxes

Total Contingent Resources


905.3 18,824 8,581 4,301 2,317 1,315
(1) "Gross" means the Company's working interest (operating or non-operating) share before deduction of royalties and without including any roya lty interests of the Company.
(2) "Contingent Resources" are the quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion of Contingent Resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.
(3) "Best Estimate" is a classification of estimated resources described in the Canadian Oil and Gas Evaluation Handbook, which is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Contingent Resources in the best estimate case have a 50% probability that the actual quantities recovered will equal or exceed the estimate.
(4) For additional information regarding 7G's inter ests in, and the location of its oil, natural gas and NGL properties, and the risks and level of uncertainty associated with the recovery of Contingent Resources, see the Company's Annual Information Form for the year ended December 31, 2014, dated March 10, 2015, which is available on SEDAR at

(5) Based upon a pre-development study. The recovery technology expected to be utilized is horizontal wells with multi-stage hydraulic fractures.
(6) There is uncertainty that it will be commercially viable to produce any portion of the Contingent Resources.
(7) Estimates of future net revenue do not represent fair market value.

In general, the significant factors that may change the Contingent Resources estimates include further delineation drilling, which could change the estimates either positively or negatively, future technology improvements, which would positively affect the estimates, and additional processing capacity that could affect the volumes recoverable or type of production. Additional facility design work, development plans, reservoir studies and delineation drilling is expected to be completed by the Company in accordance with its long-term resource development plan. Once these contingencies are removed, the resources may then b e reclassified as reserves. Generally, the timing for commercial assessments of its Contingent Resources will be determined by 7G's long-term resource development plan and its expectations for economic conditions. Management uses integrated plans to prepare future development of resources. These plans align current and planned production, current and expected market conditions, processing and pipeline capacities, capital investment commitments and related future development plans. These plans are reviewed and updated annually for internal and external factors affecting these planned activities.

The Canadian Oil and Gas Evaluation Handbook classifies a contingency as a condition that must be satisfied for a portion of Contingent Resources to be classified as reserves that is specific to the project being evaluated and expected to be resolved within a reasonable timeframe. Currently, there exists several non-technical contingencies that prevent the classification of 7G's Contingent Resource volumes as reserves. These include access to additional markets, timing of development, internal and external approvals, commitment to project development, economics and the other contingencies described in the previous paragraph.

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