The Company’s audited consolidated financial statements and corresponding Management’s Discussion and Analysis (MD&A) for the period will be available on SEDAR at www.sedar.com, on the OTCQX website at www.otcqx.com, and on PetroShale’s website at www.petroshaleinc.com. Copies of the materials can also be obtained upon request without charge by contacting the Company directly. Please note, currency figures presented herein are reflected in Canadian dollars, unless otherwise noted.
2018 FINANCIAL & OPERATING HIGHLIGHTS
- Production averaged 6,014 barrels of oil equivalent per day (“boepd”) (84% liquids) in the fourth quarter of 2018, which is 184% higher than the same period in 2017, while production averaged 5,630 boepd (87% liquids) in calendar 2018, an increase of 130% over 2017.
- On a fully diluted per share basis, fourth quarter and calendar 2018 production grew by 129% and 63%, respectively year over year.
- Revenue increased to $26.2 million in the fourth quarter of 2018 and $121.8 million in calendar 2018, driven by higher production and realized prices.
- Adjusted EBITDA increased to $11.7 million in the fourth quarter, 109% higher than the same period in 2017 reflecting a significant increase in production in the latter part of the year and offsetting weaker Bakken oil prices. For calendar 2018, adjusted EBITDA was $64.9 million, an increase of 207% over 2017.
- Adjusted EBITDA per fully diluted share was $0.06 in the fourth quarter of 2018, a 68% increase over the fourth quarter of 2017. For calendar 2018 adjusted EBITDA per fully diluted share was $0.37, a 117% increase over calendar 2017.
- Net income increased to $8.0 million in the fourth quarter of 2018 and to $27.1 million for calendar 2018 compared to net losses of $1.5 and $3.1 million in the respective prior periods of 2017. Net income per fully diluted share increased to $0.16 for 2018 from a loss of $0.03 in 2017.
- Operating netback, prior to the impact of hedging, increased by 35% to $37.07 per boe for calendar 2018.
- Capital expenditures totaled $195.2 million for the year with approximately $93.5 million (48%) directed towards acquisitions and $101.7 million (52%) for drilling, completions and construction activities.
- Over 2018, added 18.8 net locations (proved plus probable) as a result of acquisitions completed during the year.
- The borrowing base under our senior credit facility increased to US$125 million in November.
2018 RESERVES HIGHLIGHTS
- PetroShale significantly increased our oil and natural gas reserves and the estimated net present value of future net revenue (discounted at 10% -“NPV10”) across all reserve categories at year end 2018 compared to December 31, 2017:
- Proved developed producing (“PDP”) reserves grew 122% to 12.3 million boe (“MMboe”), total proved (“TP”) reserves increased 61% to 49.2 MMboe, and total proved plus probable (“P+P”) reserves increased 71% to 62.8 MMboe.
- NPV10 increased meaningfully across all categories, rising 125% for PDP to $208.4 million, 53% for TP to US$655.0 million and 73% for P+P reserves to US$850.6 million, attributable to the Company’s 2018 development program and acquisitions.
- On a fully diluted per share basis, TP reserves grew from $4.35 to $5.11 year over year and P+P reserves grew from $5.02 to $6.63.
- Net asset value per basic share increased to $5.14 based on the NPV10 of the P+P reserves after adjusting for total debt of $181.9 million with $11.1 million assumed for undeveloped land.
- PetroShale realized attractive capital efficiencies through the execution of our 2018 development program, which resulted in TP and P+P finding and development (“F&D”) costs (including change in future development capital1 or “FDC”) of $22.61 per boe and $7.82 per boe, respectively. The Company generated finding, development and acquisition (“FD&A”) costs of $17.86 per boe and $12.94 per boe, respectively on TP and P+P reserves.
- PetroShale generated TP F&D and FD&A recycle ratios of 1.6 and 2.1 times, respectively, and P+P F&D and FD&A recycle ratios of 4.7 and 2.9 times, respectively, based on our operating netback prior to hedging of $37.07 per boe.
- The three-year average P+P FD&A and F&D costs were $13.44 per boe and $12.85 per boe, resulting in a recycle ratio of 2.8 and 2.9 times, respectively.
- Our P+P Reserve Life Index (“RLI”) totaled 29 years based on annualized fourth quarter 2018 average production of 6,014 boepd.
_______________________________ |
1 Converted to Canadian dollars using the average 2018 exchange rate of US$1.00 = Cdn$1.30. |
FINANCIAL & OPERATING REVIEW
Three months ended |
Twelve months ended |
|||||||||||
FINANCIAL |
December 31, |
December 31, |
December 31, |
December 31, |
||||||||
Oil and natural gas revenue |
$ |
26,231 |
$ |
10,323 |
$ |
121,797 |
$ |
43,262 |
||||
Net income (loss) |
7,982 |
(1,482) |
27,056 |
(3,093) |
||||||||
Per share – diluted |
0.04 |
(0.02) |
0.16 |
(0.03) |
||||||||
Adjusted EBITDA(1) |
11,684 |
5,600 |
64,937 |
21,135 |
||||||||
Capital expenditures |
27,606 |
34,531 |
195,212 |
67,109 |
||||||||
Net debt(1) |
176,978 |
90,126 |
||||||||||
Common shares outstanding |
||||||||||||
Weighted average – basic |
191,040,112 |
157,127,767 |
170,866,944 |
123,279,448 |
||||||||
Weighted average – diluted |
194,482,248 |
157,127,767 |
174,391,337 |
123,279,448 |
||||||||
Three months ended |
Twelve months ended |
|||||||||||
OPERATING |
December 31, |
December 31, |
December 31, |
December 31, |
||||||||
Sales volumes |
||||||||||||
Crude Oil (Bbl/d) |
4,185 |
1,554 |
4,134 |
1,878 |
||||||||
Natural gas (Mcf/d) |
5,765 |
1,802 |
4,520 |
1,770 |
||||||||
NGLs (Bbl/d) |
868 |
266 |
743 |
272 |
||||||||
Barrels of oil equivalent (Boe/d)(2) |
6,014 |
2,121 |
5,630 |
2,445 |
||||||||
Average realized prices |
||||||||||||
Crude Oil ($/Bbl) |
$ |
64.89 |
$ |
68.38 |
$ |
77.53 |
$ |
60.28 |
||||
Natural gas ($/Mcf) |
1.24 |
1.88 |
1.17 |
1.79 |
||||||||
NGLs ($/Bbl) |
7.39 |
9.93 |
10.64 |
7.89 |
||||||||
Barrels of oil equivalent ($/Boe) |
$ |
47.41 |
$ |
52.96 |
$ |
59.27 |
$ |
48.48 |
||||
Operating netback ($/Boe) (1) (2) |
||||||||||||
Revenue |
$ |
47.41 |
$ |
52.96 |
$ |
59.27 |
$ |
48.48 |
||||
Royalties |
(9.64) |
(11.03) |
(11.73) |
(10.19) |
||||||||
Realized loss on derivatives |
(1.67) |
– |
(3.10) |
– |
||||||||
Operating costs |
(6.85) |
(5.94) |
(4.55) |
(6.15) |
||||||||
Production taxes |
(3.67) |
(3.97) |
(4.57) |
(3.65) |
||||||||
Transportation expense |
(1.68) |
(0.80) |
(1.35) |
(1.03) |
||||||||
Operating netback(1) |
$ |
23.90 |
$ |
31.22 |
$ |
33.97 |
$ |
27.46 |
||||
Operating netback prior to hedging(1) |
$ |
25.57 |
$ |
31.22 |
$ |
37.07 |
$ |
27.46 |
||||
(1) |
See “Non-IFRS measures”. |
(2) |
See “Oil and Gas Advisories”. |
2018 YEAR-END RESERVES
The reserves data in this press release is based upon an evaluation by Netherland, Sewell & Associates, Inc. (“NSAI”) with an effective date of December 31, 2018. The reserves data summarizes PetroShale’s crude oil and natural gas reserves and the net present value of future net revenue for these reserves using forecast prices and costs. All references to reserves are to gross Company reserves, meaning PetroShale’s working interest reserves before consideration of royalty interests. The reserve report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 51‑101 (“NI 51-101”) and CSA Staff Notice 51‑324. No attempt was made to evaluate possible reserves.
Gross and Net Company Interest Reserves
Reserves |
|||||||||
Tight Oil |
Shale Gas (2) |
Natural Gas Liquids (2) |
BOE |
||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||
Reserves Category |
(Mbbl) |
(Mbbl) |
(Mmcf) |
(Mmcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
|
PROVED: |
|||||||||
Developed Producing |
8,757.3 |
7,133.6 |
11,701.3 |
9,558.6 |
1,556.6 |
1,247.8 |
12,264.1 |
9,974.5 |
|
Developed Non-Producing |
– |
– |
– |
– |
– |
– |
– |
– |
|
Undeveloped |
28,715.8 |
23,618.5 |
25,961.3 |
21,397.0 |
3,875.0 |
3,128.5 |
36,917.7 |
30,313.2 |
|
TOTAL PROVED |
37,473.1 |
30,752.1 |
37,662.6 |
30,955.5 |
5,431.6 |
4,376.3 |
49,181.8 |
40,287.7 |
|
PROBABLE |
10,407.2 |
8,420.8 |
10,301.6 |
8,367.1 |
1,490.5 |
1,191.3 |
13,614.6 |
11,006.6 |
|
TOTAL PROVED PLUS PROBABLE |
47,880.3 |
39,172.9 |
47,964.3 |
39,322.7 |
6,922.1 |
5,567.6 |
62,796.5 |
51,294.3 |
Notes: |
|
(1) |
Columns may not add due to rounding. |
(2) |
All of our shale gas reserves and natural gas liquids are produced in solution with our tight oil. The natural gas liquid reserves are recovered from our natural gas reserves downstream of the wellhead. |
Net Present Value of Future Net Revenue
Before Income Taxes Discounted at (%/year) |
||||||
0% |
5% |
10% |
15% |
20% |
||
Reserves Category |
($US 000s) |
($US 000s) |
($US 000s) |
($US 000s) |
($US 000s) |
|
PROVED: |
||||||
Developed Producing |
360,580.9 |
263,316.2 |
208,352.3 |
173,847.8 |
150,378.8 |
|
Developed Non-Producing |
– |
– |
– |
– |
– |
|
Undeveloped |
1,045,930.3 |
652,037.4 |
446,642.2 |
324,574.1 |
245,064.3 |
|
TOTAL PROVED |
1,406,511.2 |
915,353.6 |
654,994.5 |
498,421.8 |
395,443.2 |
|
PROBABLE |
469,547.3 |
285,215.4 |
195,621.9 |
144,834.9 |
112,792.6 |
|
TOTAL PROVED PLUS PROBABLE |
1,876,058.4 |
1,200,569.0 |
850,616.4 |
643,256.7 |
508,235.8 |
Note: |
|
(1) |
Columns may not add due to rounding. |
As a reporting issuer in Canada, PetroShale is required to report our reserves and NPV10 using forecast pricing and costs, as stipulated under NI 51-101. The forecast prices reflected in the NPV10 is included in our 2018 Annual Information Form, expected to be filed on SEDAR before the end of April, 2019.
Reserves Reconciliation
Total (Mboe) |
||||
Total Proved |
Probable |
Total Proved Plus |
||
December 31, 2017 |
30,602.5 |
6,134.6 |
36,737.0 |
|
Discoveries |
– |
– |
– |
|
Extensions and Improved Recovery |
– |
– |
– |
|
Product Type Transfers(1) |
2,613.0 |
415.6 |
3,028.6 |
|
Technical Revisions(2) |
313.3 |
4,438.4 |
4,751.7 |
|
Acquisitions(3) |
17,769.3 |
2,636.4 |
20,405.8 |
|
Dispositions |
– |
– |
– |
|
Economic Factors |
(61.6) |
(10.4) |
(72.0) |
|
Production |
(2,054.7) |
– |
(2,054.7) |
|
December 31, 2018(4) |
49,181.9 |
13,614.6 |
62,796.5 |
Notes: |
|
(1) |
Product type transfers reflects the initial inclusion of NGLs in the Company’s reserves beginning on January 1st, 2018, and the offsetting adjustment to wellhead gas as a result of NGL recovery. |
(2) |
Technical revisions include removal of locations based on development permitting and activity of our operators on non-operated properties and probable reserve assignments to proved well locations. Additionally, it reflects changes to reserves based on estimates from further production information gathered in 2018 from our wells and analogous wells near our lands, and revisions to interest on certain non-operated wells. |
(3) |
The acquisitions amount is the estimate of reserves at December 31, 2018, adjusted for production associated with the acquired properties from the related acquisition date to December 31, 2018. |
(4) |
Columns may not add due to rounding. |
2018 Capital Program Efficiency
Finding, Development & |
Finding & |
||||
Total Proved |
Proved plus |
Total Proved |
Proved plus |
||
Capital Costs ($000s) |
|||||
Acquisitions |
93,520 |
93,520 |
– |
– |
|
Capital expenditures |
101,692 |
101,692 |
101,692 |
101,692 |
|
Change in future development capital |
173,406 |
168,477 |
(36,498) |
(41,428) |
|
Total FD&A / F&D Costs |
368,618 |
363,689 |
65,194 |
60,264 |
|
Reserves additions (Mboe) |
|||||
Net change in reserve volumes |
18,579 |
26,059 |
18,579 |
26,059 |
|
Add back production |
2,055 |
2,055 |
2,055 |
2,055 |
|
Reserves associated with acquisitions |
– |
– |
(17,769) |
(20,406) |
|
Total additions |
20,634 |
28,114 |
2,865 |
7,708 |
|
FD&A and F&D Costs ($/boe) |
$17.86 |
$12.94 |
$22.76 |
$7.82 |
|
Three Year FD&A and F&D Costs ($/boe)(2) |
$16.97 |
$13.44 |
$22.61 |
$12.85 |
|
Recycle Ratio(3) |
2.1 |
2.9 |
1.6 |
4.7 |
|
Three Year Recycle Ratio(4) |
2.2 |
2.8 |
1.6 |
2.9 |
Notes: |
|
(1) |
The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and probable reserves into production. The FDC was converted to Canadian dollars using the average 2018 exchange rate of US$1.00 = Cdn$1.30. In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures, after changes in FDC, by the applicable reserves additions. We have disclosed both finding and development costs and finding, development and acquisition costs because acquisition costs have been a significant component of our total capital expenditures and strategy, and also due to the difficulty in allocating changes in future development costs between reserve additions from drilling, technical revisions and acquisitions. For purposes of calculating finding and development costs, we have chosen to reflect the change in future development costs associated with drilling activity during the year and exclude the increase in future development costs associated with acquisitions. |
(2) |
The calculation of the three year FD&A and F&D costs reflect the sum of the capital costs and net reserve additions for the years 2016 through 2018. |
(3) |
Recycle ratio is defined as operating netback for 2018, divided by F&D or FD&A costs, as applicable, on a per boe basis. Operating netback is calculated as revenue (excluding realized hedging gains and losses) minus royalties, operating costs, production taxes and transportation expense. PetroShale’s operating netback (prior to hedging) in 2018 averaged $37.07 per boe. |
(4) |
The calculation of the three year recycle ratio reflects the operating netback (prior to hedging) for calendar year 2018, divided by the three year F&D or FD&A costs, as applicable, on a per boe basis. |
Net Asset Value (“NAV”) per Share as at December 31, 2018
($ thousands, except share and per share amounts)
Proved Plus Probable Reserve Value (NPV10 Before Tax) |
$ 1,156,838 |
|||||
Undeveloped Land Value |
11,098 |
|||||
Net Debt (including Decommissioning Obligation)(1) |
(181,912) |
|||||
Total Net Assets |
$ 986,023 |
|||||
Common Shares Outstanding |
191,758,236 |
|||||
Estimated Net Asset Value per Basic Common Share(2) |
$ 5.14 |
|||||
Estimated Net Asset Value per Diluted Common Share |
$5.04 |
|||||
Estimated Net Asset Value per Diluted Common Share (assuming exchange of Preferred Shares) |
$4.20 |
Notes: |
|
(1) |
See “Non-IFRS Measures”. |
(2) |
Net asset value is calculated as at a particular date and is, by its nature, historical, and may not be reflective of PetroShale’s future performance. The NAV reflects the NPV10 of the Company’s reserves at an exchange rate of US$1.00 = Cdn$1.36, which was the market rate at December 31, 2018. |
MESSAGE FROM THE CEO
PetroShale recorded another very active year with ongoing operated and non-operated development activity and strategic acquisitions of high-quality assets in the heart of the North Dakota Bakken/ Three Forks play. As a result of these efforts, the Company achieved significant growth in reserves on both an absolute and per share basis, generated significantly higher adjusted EBITDA and increased average annual production by 130% over 2017.
Early in 2018, PetroShale completed a strategic financing with a private equity investor based in the U.S. with proceeds used to retire the Company’s previous subordinated loan facility via the issuing of US$75 million of preferred shares having a five year term and 9% coupon. We further enhanced our financial flexibility through 2018 by increasing the borrowing capacity of our senior credit facility to US$125 million, which currently affords PetroShale substantial undrawn credit capacity of US$57 million to carry out our ongoing drilling and completion programs and to pursue further accretive and strategic acquisitions. In addition to our robust liquidity, the balance sheet remains strong with senior debt at 1.1 times adjusted EBITDA at December 31, 2018.
During the year, we invested $101.7 million in drilling, completions and construction expenditures for the drilling of 37 gross (6.4 net) wells and the completion of 31 gross (7.88 net) wells. Major operated drilling activity included the drilling of seven (6.1 net) wells in our Horse Camp West, Primus East and Bear Chase units. Major operated completion activity included completing six gross (5.5 net) wells in our Primus West, Horse Camp West and Horse Camp East units. Major non-operated activity included participating in the drilling of three (0.8 net) wells at the Jore unit and completion of four (1.6 net) wells at the Packineau unit.
In 2018, we closed a strategic acquisition of assets within our North Dakota Bakken core area which included approximately 550 boepd of low decline production (~90% light oil and liquids), as well as significant working interests in three primarily undeveloped drilling units that will be operated by PetroShale (the “Acquisition”). The Acquisition added 14.3 net locations (proved plus probable) to our inventory of low-risk infill drilling locations. Concurrent with the Acquisition, we closed a bought deal public equity financing and private placement financing (the “Equity Financings”), raising aggregate gross proceeds of $58.5 million. Net proceeds from the Equity Financings, along with a US$10.5 million draw on PetroShale’s senior credit facility, were used to fund the Acquisition.
WTI benchmark and Bakken differential prices remained strong through most of 2018, averaging approximately US$64.76 and US$5.12 per Bbl, respectively. Higher oil prices and net production volumes during the first nine months of 2018 led to higher Company revenue, cash flow from operations and adjusted EBITDA relative to the same period in 2017. However, during the fourth quarter WTI oil prices decreased to an average of US$58.70 per Bbl. In addition, the average Bakken oil price differential to WTI widened significantly to US$9.61 per Bbl due to refinery maintenance and a surplus of Canadian oil supply, all of which negatively impacted our operating netback in Q4 2018, which averaged $23.90 per Boe ($25.57 per Boe prior to hedging). As anticipated, the Bakken differential narrowed in the first few months of 2019 following a return of refinery capacity and stabilization of Canadian oil supply as a result of Alberta production cuts.
OUTLOOK
The Company remains active in 2019, executing a continuous development program with one operated rig and participating in various non-operated wells. During the first quarter of 2019 we drilled two gross (1.0 net) wells in our Helen unit and are currently drilling four (2.2 net) wells at our Thunder Cloud unit. We are in the process of completing two (1.4 net) wells at our Primus East unit where we will commission facilities later in the second quarter. Also in the second quarter we plan to frac three gross (2.8 net) wells in our Bear Chase unit that we plan to bring on line in the third quarter of 2019.
Our production in the first half of 2019 has been impacted by one-time events as we shut-in certain wells to protect them from nearby fracing activities and/or to install artificial lift. These events, as well as natural declines, will lead to average production in the first half of 2019 between 5,000 to 6,000 boepd. We expect significantly higher average production in the second half of 2019 of 10,000 to 11,000 boepd with an estimated 2019 exit rate of approximately 11,000 boepd.
PetroShale had a strong 2018 with substantial growth in production, EBITDA and reserves. Going forward, we are well positioned in 2019 to continue executing our oil-focused, Bakken strategy with plans to continue increasing production with the drilling of approximately 20 gross (9.0 net) wells, of which 6.8 net wells will be operated.
As always, we wish to thank all of PetroShale’s employees, directors and shareholders for your continued support and look forward to updating you on our progress and achievements in the future.
((signed))
Mike Wood
President & CEO
About PetroShale
PetroShale is an oil company engaged in the acquisition, development and production of top-tier oil-weighted assets in the North Dakota Bakken / Three Forks.