Mr. Paul Wanklyn reports
CEQUENCE ENERGY ANNOUNCES OPERATIONAL UPDATE AND 2014 RESERVES AND FINANCIAL AND OPERATING RESULTS
Cequence Energy Ltd. has released its operating and financial results for the periods ended Dec. 31, 2014, the results of its year-end independent reserve evaluation, and is providing an operational update. The company's audited consolidated financial statements and management's discussion and analysis are available at its website and on SEDAR.
Highlights for 2014 include:
- Increased annual funds flow by 38 per cent to $70.7-million, or 33 cents per share;
- Increased annual average production by 7 per cent to 10,932 barrels of oil equivalent per day;
- Reduced fourth quarter operating costs by 9 per cent over fourth quarter 2013 to $6.67 per boe;
- Realized a gain of $92-million on the disposition of the Ansell property for $140-million;
- Maintained a strong balance sheet through declining commodity prices with a trailing-debt-to-cash-flow ratio of 1.0 times;
- Initiated a 13-well horizontal development program at Simonette including successfully executing multiwell pad drilling and more intense completion techniques;
- Efficiently added reserves with proved plus probable finding, development and acquisition costs (FD&A costs) of $10.26 and proved FD&A costs of $3.97;
- Increased proved developed producing reserves by 16 per cent from the prior year to 18.7 million boe (mmboe);
- Increased proved plus probable reserves to 118 mmboe with a net present value at a 10-per-cent discount of $854-million;
- Achieved current production of 12,500 boepd with 2,700 boepd of production tested and awaiting tie-in or shut-in due to infrastructure constraints.
"Our drive to become a focused Deep basin Montney producer continued in 2014," said Paul Wanklyn, president and chief executive officer. "We monetized our Ansell property for a significant gain and, despite losing 1,600 boepd through the sale of the property, Cequence achieved yearly average production of 10,932 boepd, or 7-per-cent growth over 2013. Important changes were made to our completion methods since first quarter 2014, which resulted in the successful completion of 10 Montney wells and three Cretaceous wells through our fall/winter drilling program. We are extremely pleased with both the execution success achieved by our team, and the initiation of pad-style drilling operations at our Simonette field."
Operations update
During the winter program Cequence drilled 13 gross (10.95 net) horizontal wells including 10 gross (nine net) Montney wells from three separate pad locations. Drilling performance continues to improve, with recent Montney pad wells six days faster than earlier pad wells. Completion intensity was increased to one tonne of sand per lateral metre compared with historical stimulations of 0.5 tonne of sand per lateral metre. This 100-per-cent increase in completion intensity was accomplished with only a 10-per-cent increase in average completion costs. The last three wells drilled from the 1-32 padsite however had an average well cost of $8.7-million per well, or 8 per cent lower than 2013/2014 completion intensity wells. As a result of the development style of this year's capital program, seven of the 10 Montney completions were flowed in line to sales during cleanup.
MONTNEY WELL RESULTS -- CUMULATIVE PRODUCTION RATES
Final test rate IP 30 production
Pad Wells Gas Free condensate Gas Free condensate
(mmcf/d) (bbl/d) (bbl/mmcf) (mmcf/d) (bbl/d) (bbl/mmcf)
01-32 6 33.3 1,695 50.9 26.5 848 32.0
12-26 2 12.4 222 17.9 9.5 156 16.4
15-15 2 13.6 368 27.1 Forecast on production March 15
Average per well 5.9 229 38.8 4.5 126 28.0
DUNVEGAN AND FALHER WELL RESULTS -- PRODUCTION RATES
Final test rate IP 30 production
Well Zone Gas Free condensate Gas Free condensate
(mmcf/d) (bbl/d) (bbl/mmcf) (mmcf/d) (bbl/d) (bbl/mmcf)
11-12 Dunvegan 6.8 118 17.4 8.1 174 21.5
8-18 Falher 2.1 15 7.1 1.6 13 8.2
2-11 Dunvegan 8.9 113 12.7 On production March 4
Average per well 5.9 83 14.1 4.9 94 19.2
Production and facilities
Cequence completed the expansion of its Simonette 13-11-62-27W5 facility in January resulting in current capacity of 100 million cubic feet per day. The Simonette field was down for seven days in January, associated with the final installation of the new equipment and was restarted on Jan. 13, 2015. Since Jan. 15, Cequence has averaged approximately 12,200 boe per day despite pipeline maintenance restrictions on the TCPL system and related increased industry volume constraints that cascaded onto the Alliance/Aux Sable system. The TCPL pipeline maintenance impacts may last until third quarter 2015 and will restrict peak production volumes from the Simonette property.
Current field estimated production is 12,500 boepd with 1,200 boepd of net tested production expected to be tied in in mid-March, with another 1,500 boepd shut in due to infrastructure capacity restrictions. Despite these curtailments and a strategically reduced capital budget, Cequence expects production to average 11,500 boepd for the year, or a 5-per-cent increase compared with 2014.
FINANCIAL AND OPERATING HIGHLIGHTS
(In thousands, except per share and per unit)
Three months ended Dec. 31, 12 months ended Dec. 31,
2014 2013 2014 2013
Production revenue $ 25,566 $ 28,483 $136,893 $105,617
Comprehensive income (loss) (4,422) (827) 79,368 (2,613)
Per share -- basic (0.02) (0.00) 0.38 (0.01)
Per share -- diluted (0.02) (0.00) 0.37 (0.01)
Funds flow from operations 13,745 14,855 70,650 51,312
Per share -- basic 0.07 0.07 0.33 0.25
Per share -- diluted 0.06 0.07 0.33 0.25
Production volumes
Natural gas (Mcf/d) 49,265 53,433 55,826 52,705
Crude oil (bbl/d) 97 119 118 125
Natural gas liquids (bbl/d) 541 569 583 524
Condensate (bbl/d) 872 800 927 750
Total (boe/d) 9,720 10,394 10,932 10,183
Sales prices
Natural gas, including realized hedges ($/Mcf) 3.92 3.82 4.54 3.57
Crude oil ($/bbl) 73.15 78.56 89.76 86.46
Natural gas liquids ($/bbl) 29.67 44.46 41.10 39.72
Condensate ($/bbl) 70.59 88.44 94.04 92.52
Total ($/boe) 28.59 29.79 34.31 28.42
Netback ($/boe)
Price $ 28.59 $ 29.79 $ 34.31 $ 28.42
Royalties (1.25) (1.85) (3.51) (2.32)
Transportation (1.48) (1.62) (1.48) (1.60)
Operating costs (6.67) (7.33) (7.63) (7.66)
Operating netback 19.19 18.99 21.69 16.84
General and administrative (2.27) (1.65) (2.21) (1.95)
Interest (1.87) (1.77) (1.87) (0.93)
Cash netback 15.05 15.57 17.61 13.96
Capital expenditures
Capital expenditures 56,472 51,578 180,215 117,909
Net acquisitions (dispositions) (2,381) (47) (150,782) (2,675)
Total capital expenditures 54,091 51,531 29,433 115,234
Net debt and working capital (deficiency) (71,354) (111,433) (71,354) (111,433)
Financial
Funds flow from operations increased to $70.7-million for 2014 compared with $51.3-million for the 2013. The increase in funds flow from operations is due largely to higher realized oil and natural gas prices and a 7-per-cent increase in production volumes. Funds flow from operations was $13.7-million for the three months ended Dec. 31, 2014, compared with $14.9-million for the three months ended Dec. 31, 2013. Fourth quarter production volumes were down 6 per cent from 2013 and average sales prices decreased by 4 per cent from the prior year.
Comprehensive income for the year ended Dec. 31, 2014, was $79.4-million compared with a $2.6-million loss in 2013. The increase in earnings is due to gains realized on the sale of oil and gas properties in the year of $99.8-million and higher commodity prices, offset partially by increases in future income taxes, depletion and impairment. Cequence recorded a comprehensive loss of $4.4-million for the fourth quarter of 2014 compared with comprehensive loss of $800,000 in the same period in 2013. The loss in the fourth quarter of 2014 is a result of impairment charges of $18.4-million offset by an unrealized hedging gain of $10.6-million.
Capital expenditures, prior to acquisition and dispositions, were $56.5-million in the fourth quarter of 2014 and $180.2-million for the year ended Dec. 31, 2013. For the year ended Dec. 31, 2014, Cequence participated in drilling 20 (14.9 net) wells. Net of acquisitions and dispositions of $150.8-million, capital expenditures were $29.4-million for the year ended Dec. 31, 2014.
The company is well positioned to weather the current period of low commodity prices. The company exited 2014 with available credit facilities of $195-million versus net debt of $71.4-million. On a trailing 12-month basis, the net-debt-to-cash-flow ratio is 1.0 times. Net debt comprises $60-million in senior notes carrying a five-year term and a working capital deficiency of $11.4-million. The company's senior credit facility was undrawn at Dec. 31, 2014.
Outlook and guidance
Balance sheet strength remains critically important to the company's strategy of maximizing shareholder value through profitable growth. In response to weak commodity prices, the company reduced capital spending in the first half of 2015 to $22-million and spending will approximate cash flow over this period. Budgeted capital expenditures for 2015 are $60-million and will include (five) 4.2 net horizontal wells to be drilled at Simonette in the second half of 2015. The company will continue to monitor fluctuations in commodity prices and may adjust capital spending based on the company's hedge position and short- to medium-term crude oil and natural gas prices.
Cequence anticipates production growth of 5 per cent in 2015 based largely on the success of the 2014/2015 winter drilling program. Annual production volumes are expected to average 11,500 boepd for the year ended Dec. 31, 2014.
First quarter production is expected to average 11,500 boepd, compared with 12,500 to 13,000 boepd as previously guided due to on stream delays and recent maintenance to the TransCanada system and the resulting spillover of production volumes filling existing Alliance capacity. Cequence expects the maintenance issues to be continuing through September, 2015.
The company has hedged approximately half of its 2015 natural gas production at an average price of $3.84 per thousand cubic feet and will continue to actively hedge production to protect future capital spending programs. Based on AECO natural gas prices of $2.65/gigajoule, annual funds flow is forecast to be approximately $40-million resulting in net debt of approximately $90-million at Dec. 31, 2015.
GUIDANCE
Previous 2015 (three months) Revised 2015 (three months) Guidance 2015
Average production (boe/d) 12,500-13,000 11,500 11,500
Funds flow from operations $12,000 $10,000 $40,000
Funds flow from operations per share $0.06 $ 0.05 $0.19
Capital expenditures,
prior to dispositions $22,000 $22,000 $60,000
Wells drilled 5 (4.7) 5 (4.7) 10 (9.2)
Operating and transportation
costs ($ per boe) $8.20 $8.80 $8.80
G&A costs ($ per boe) $1.90 $2.50 $2.50
Royalties (% revenue) 10 10 10
Crude -- WTI (US$/bbl) $50.00 $50.00 $50.00
Natural gas -- AECO $/gj) $2.65 $2.65 $2.65
Period-end, net debt and
working capital deficiency $85,000 $85,000 $90,000
Reserves
The following highlights are based on the reserve report effective Dec. 31, 2014, prepared by GLJ Petroleum Consultants:
- Increased proved developed producing reserves by 16 per cent from the prior year to 18.7 mmboe;
- Increased proved reserves by 3 per cent from the prior year to 57.1 mmboe;
- Increased proved plus probable reserves by 4 per cent from the prior year to 118.1 mmboe;
- Achieved FD&A costs (including changes to FDC) of $10.26 per boe on a proved-plus-probable basis and $3.97 per boe on a proved basis;
- Achieved F&D (finding and development) costs (including changes to FDC) of $13.82 per boe on a proved-plus-probable basis and $16.66 per boe on a proved basis;
- Achieved an FD&A recycle ratio of 2.1 times based on the 2014 operating netback of $21.69;
- Net present value before income taxes of the company's proved plus probable reserves is $854-million, or $4.05 per share (using a discount rate of 10 per cent);
- Replaced 227 per cent of production with proved plus probable reserve additions.
In accordance with National Instrument 51-101, GLJ prepared the GLJ report for the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence.
The tables are a summary of the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ report based on forecast price and cost assumptions. It should not be assumed that the estimates of future net revenues presented in the tables represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of Cequence's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
SUMMARY OF OIL, NATURAL GAS AND NGL RESERVES
Light and medium crude oil NGL Natural gas Total oil equivalent
Reserves category Gross Net Gross Net Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mboe) (Mboe)
Proved
Developed producing 1,595 1,106 997 854 96,604 84,834 18,693 16,099
Developed non-producing 523 363 273 240 25,423 22,176 5,033 4,299
Undeveloped 3,537 2,586 1,774 1,643 168,474 148,229 33,390 28,934
Total proved 5,655 4,055 3,043 2,737 290,500 255,239 57,115 49,332
Probable 6,315 4,328 3,200 2,926 308,409 268,558 60,917 52,014
Total proved plus probable 11,971 8,383 6,243 5,663 598,909 523,797 118,032 101,346
(1) Columns may not add due to rounding.
(2) Gross reserves mean the company's working interest (operated and non-operated) share before deduction
of royalties payable to others and without including any royalty interests of the company.
(3) Net reserves mean the company's working interest (operated and non-operated) share after deduction of
royalty obligations plus the company's royalty interests in reserves.
SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE
Reserves category Before future income tax expenses discounted at (%/year)
0 5 10 15 20 10
(M$) (M$) (M$) (M$) (M$) ($/mcfe)
Proved
Developed producing 288,076 232,727 195,984 170,101 150,970 2.03
Developed non-producing 88,906 68,135 55,167 46,415 40,140 2.14
Undeveloped 471,949 296,967 196,335 133,513 91,870 1.13
Total proved 848,931 597,829 447,485 350,029 282,980 1.51
Probable 1,157,793 651,276 406,738 270,841 187,791 1.30
Total proved plus probable 2,006,724 1,249,105 854,223 620,870 470,771 1.40
Reserves category After future income tax expenses discounted at (%/year)
0 5 10 15 20
(M$) (M$) (M$) (M$) (M$)
Proved
Developed producing 288,076 232,727 195,984 170,101 150,970
Developed non-producing 88,906 68,135 55,167 46,415 40,140
Undeveloped 412,255 265,896 179,061 123,389 85,675
Total proved 789,237 566,758 430,211 339,905 276,786
Probable 867,481 481,142 294,925 191,954 129,495
Total proved plus probable 1,656,719 1,047,900 725,137 531,859 406,281
(1) Columns may not add due to rounding.
(2) It should not be assumed that the undiscounted and discounted future net revenues
estimated by GLJ represent the fair market value of the reserves.
GLJ employed the pricing, exchange rate and inflation rate assumptions as of Jan. 1, 2015, in the GLJ report in estimating Cequence's reserves data using forecast prices and costs.
PRICING FORECAST
Year Natural gas Light crude oil Pentanes plus
Henry Hub AECO gas price WTI Edmonton Edmonton Inflation rate Exchange rate
($US/MMBtu) ($/MMBtu) ($US/bbl) ($/bbl) ($/bbl) (%/year) ($US/$)
2015 3.31 3.31 62.50 64.71 69.24 2.0 0.850
2016 3.75 3.77 75.00 80.00 85.60 2.0 0.875
2017 4.00 4.02 80.00 85.71 91.71 2.0 0.875
2018 4.25 4.27 85.00 91.43 97.83 2.0 0.875
2019 4.50 4.53 90.00 97.14 103.94 2.0 0.875
2020 4.75 4.78 95.00 102.86 110.06 2.0 0.875
2021 5.00 5.03 98.54 106.18 113.62 2.0 0.875
2022 5.25 5.28 100.51 108.31 115.89 2.0 0.875
2023 5.50 5.53 102.52 110.47 118.20 2.0 0.875
2024 5.68 5.71 104.57 112.67 120.56 2.0 0.875
Thereafter escalation rate of 2 per cent.FD&A and F&D both including and excluding FDC have been calculated in accordance with NI 51-101. Cequence's finding, development and acquisition costs are as shown in the table.
FINDING, DEVELOPMENT AND ACQUISITION COSTS
Proved Proved plus probable
FD&A including change in FDC
2014 FD&A costs ($000) 29,433 29,433
2014 change in FDC ($000) (5,871) (63,886)
2014 capital expenditures including change in FDC ($000) 23,562 93,319
2014 reserve additions (Mboe) 5,939 9,091
2014 FD&A including change in FDC ($/boe) 3.97 10.26
Three-year average FD&A including change in FDC ($/boe) 11.68 10.77
F&D including change in FDC
2014 F&D costs ($000) 180,215 180,215
2014 change in FDC ($000) 30,625 133,859
2014 capital expenditures including change in FDC ($000) 210,840 314,074
2014 reserve additions (Mboe) 12,657 22,727
2014 F&D including change in FDC ($/boe) 16.66 13.82
Three-year average F&D including change in FDC ($/boe) 14.12 11.63
FDC -- Dec. 31, 2014 ($000) 381,427 849,135
FDC -- Dec. 31, 2013 ($000) 387,298 785,249
2014 change in FDC ($000) (5,871) 63,886
FDC related to 2014 net acquisitions (dispositions) ($000) 36,496 69,973
2014 change in FDC excluding FDC on net acquisitions (dispositions) ($000) 30,625 133,859
(1) In addition to F&D costs, Cequence also calculates FD&A costs which incorporate both the costs and
associated reserve additions related to acquisitions net of any dispositions during the year. Since
acquisitions can have a significant impact on Cequence's annual reserve replacement costs, the company
believes that FD&A costs provide a more meaningful portrayal of Cequence's cost structure.
(2) Capital expenditures for the FD&A calculation include cash expenditures on property and equipment, and
exploration and evaluation expenditures of $180,215, net cash expenditures on property acquisition and
dispositions of $150,782.We seek Safe Harbor.
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