CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) – Raging River Exploration Inc. (the “Company” or “Raging River”) (TSX:RRX) announces its operating and financial results for the three and six months ended June 30, 2017. Selected financial and operational information is outlined below and should be read in conjunction with the unaudited interim financial statements and the related management’s discussion and analysis (“MD&A”). These filings will be available at www.sedar.com and the Company’s website at www.rrexploration.com.
Financial and Operating Highlights
| Three months ended June 30, |
Percent Change | Six months ended June 30, |
Percent Change | |||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||
| Financial (thousands of dollars except share data) | ||||||||||||||
| Petroleum and natural gas revenue | 105,982 | 67,528 | 57 | 217,999 | 117,909 | 85 | ||||||||
| Funds from operations (1) | 64,965 | 43,999 | 48 | 137,717 | 73,901 | 86 | ||||||||
| Per share – basic | 0.28 | 0.19 | 47 | 0.60 | 0.33 | 82 | ||||||||
| – diluted | 0.28 | 0.19 | 47 | 0.60 | 0.33 | 82 | ||||||||
| Net earnings (loss) | 18,595 | 5,320 | 250 | 33,938 | (2,534) | 1439 | ||||||||
| Per share – basic | 0.08 | 0.02 | 300 | 0.15 | (0.01) | 1600 | ||||||||
| – diluted | 0.08 | 0.02 | 300 | 0.15 | (0.01) | 1600 | ||||||||
| Development capital expenditures | 68,640 | 38,602 | 78 | 181,323 | 75,982 | 139 | ||||||||
| Property and corporate acquisitions | – | 25,125 | (100) | – | 25,125 | (100) | ||||||||
| Total capital expenditures | 68,640 | 63,727 | 8 | 181,323 | 101,107 | 79 | ||||||||
| Net debt(1)(3) | 253,117 | 63,101 | 301 | |||||||||||
| Shareholders’ equity | 938,337 | 826,775 | 13 | |||||||||||
| Weighted average shares (thousands) | ||||||||||||||
| Basic | 231,178 | 226,231 | 2 | 231,165 | 221,362 | 4 | ||||||||
| Diluted | 231,335 | 227,167 | 2 | 231,402 | 221,362 | 5 | ||||||||
| Shares outstanding, end of period (thousands) | ||||||||||||||
| Basic | 231,243 | 226,600 | 2 | |||||||||||
| Diluted | 232,979 | 236,768 | (2) | |||||||||||
| Operating (6:1 boe conversion) | ||||||||||||||
| Average daily production | ||||||||||||||
| Crude oil and NGLs (bbls/d) | 18,795 | 14,603 | 29 | 19,134 | 14,818 | 29 | ||||||||
| Heavy crude oil (bbls/d) | 1,189 | 171 | 595 | 1,303 | 163 | 699 | ||||||||
| Natural gas (mcf/d) | 12,185 | 7,368 | 65 | 11,676 | 7,634 | 53 | ||||||||
| Barrels of oil equivalent (2)(boe/d) | 22,015 | 16,002 | 38 | 22,383 | 16,253 | 38 | ||||||||
| Netbacks ($/boe) | ||||||||||||||
| Operating | ||||||||||||||
| Oil and gas sales(3) | 52.90 | 46.37 | 14 | 53.81 | 39.86 | 35 | ||||||||
| Royalties | (5.05) | (4.54) | 11 | (5.14) | (3.89) | 32 | ||||||||
| Operating expenses | (11.31) | (8.98) | 26 | (10.90) | (8.97) | 22 | ||||||||
| Transportation expenses | (1.41) | (1.39) | 1 | (1.43) | (1.38) | 4 | ||||||||
| Field netback(1) | 35.13 | 31.46 | 12 | 36.34 | 25.62 | 42 | ||||||||
| Realized gain (loss) on commodity contracts | (0.37) | 0.11 | (436) | (0.12) | 0.12 | (200) | ||||||||
| Operating netback | 34.76 | 31.57 | 10 | 36.22 | 25.74 | 41 | ||||||||
| General and administrative expense | (1.05) | (1.20) | (13) | (1.04) | (1.23) | (15) | ||||||||
| Financial charges | (1.14) | (0.46) | 148 | (1.07) | (0.64) | 67 | ||||||||
| Asset retirement expenditures | (0.15) | (0.04) | 275 | (0.13) | (0.04) | 225 | ||||||||
| Current taxes recovery | – | 0.34 | (100) | – | 1.15 | (100) | ||||||||
| Funds flow netback(1) | 32.42 | 30.21 | 7 | 33.98 | 24.98 | 36 | ||||||||
| Net earnings (loss) per boe | 9.28 | 3.66 | 154 | 8.36 | (0.86) | 1072 | ||||||||
| Wells drilled(4) | ||||||||||||||
| Gross | 64 | 40 | 60 | 163 | 97 | 68 | ||||||||
| Net | 60.6 | 39.9 | 52 | 155.1 | 96.4 | 61 | ||||||||
| Success | 97% | 98% | (1) | 98% | 99% | (1) | ||||||||
| (1) See “Non-IFRS Measures.” |
| (2) See ‘”Barrels of Oil Equivalent.” |
| (3) Excludes unrealized risk management contracts. |
| (4) Excludes injection and service wells. |
SECOND QUARTER 2017 HIGHLIGHTS
- Achieved quarterly average production of 22,015 boe/d (91% oil), an increase of 38% over the comparable period in 2016. This represents a 35% production per share increase from the comparable period of 2016.
- The Company’s capital expenditures were $68.6 million inclusive of $9 million on land and $59.6 million of development capital resulting in the drilling of 60.6 net Viking horizontal wells at a 97% success rate.
- Achieved funds flow from operations (“FFO”) of $65 million ($0.28/share basic), an increase of 48% from the second quarter of 2016.
- Generated second quarter net earnings of $18.6 million ($0.08/share basic), an increase of 250% from the second quarter 2016.
- The Company generated field operating netbacks of $35.13/boe and funds flow netbacks of $32.42/boe.
- Continued diligent cost control with top decile general and administrative costs of $1.05/boe, a reduction of 13% from the comparable period in 2016.
- Maintained balance sheet strength with second quarter exit net debt of $253.1 million representing 1.0 times debt to the second quarter annualized FFO.
CREDIT FACILITY EXPANSION
As a result of the Company’s continued operational success, effective July 31, 2017, Raging River’s borrowing base on its credit facilities was increased to $500 million from $400 million. The increased credit facilities are comprised of a $50 million non-syndicated operating facility and a $450 million syndicated extendible revolving facility, on similar terms and conditions to the pre-existing facilities.
Our commitment to balance sheet strength remains paramount with the Company now anticipating exit 2017 net debt of approximately $285 million representing a net debt to expected trailing fourth quarter FFO of approximately 1.1 times based on current strip WTI pricing of approximately US$49.80/bbl.
OPERATIONS UPDATE
In the second quarter of 2017, field conditions were very cooperative and the Company had timely access to services. As a result, Raging River was able to drill 60.6 net wells, a record level of second quarter activity for the Company.
In the second quarter, of the 60.6 net wells drilled, 16 wells were extended reach horizontals (“ERH”) bringing the total producing ERH well count to 89. Average per well ERH results continue to show 1.8 – 2.0 times improvement over comparable offsetting short laterals. For the remainder of 2017, it is expected that approximately 60% of wells drilled will be ERH.
Average well costs year to date have been $670 thousand for short laterals and $900 thousand blended cost for 3/4 mile and 1 mile ERH wells. Average well costs are on budget with our anticipated 5-7% increase from the lows of 2016. We anticipate costs to remain flat through the remainder of 2017.
GUIDANCE AND OUTLOOK
Raging River’s 2017 capital budget and guidance remains unchanged with targeted annual average production of 22,750 boe/d and capital spending of $340 million.
Two key initiatives that were outlined in the May 8, 2017 press release include the allocation of: (i) $10 million of incremental capital towards waterflood related facilities at Gleneath and Eureka; and (ii) $10 million of capital to new play development. The Company has made good progress on both of these initiatives.
The Company is on track with the waterflood related facility projects which are set to commence in the third quarter of 2017 and to be completed by the year end. Operating cost savings associated with these expenditures are expected to be seen in 2018.
With respect to the new play development initiative, as disclosed in the June 5, 2017, press release, Raging River has been accumulating lands prospective for light oil in the East Duvernay Shale basin in central Alberta. We have continued to make progress with this initiative, and have increased our net land position from 100,000 to 130,000 net acres. All of the lands acquired to date are targeting the oil phase of the basin.
The Company plans to methodically evaluate this East Duvernay Shale opportunity. We are currently surveying and acquiring surface lands in multiple locations in anticipation of drilling the first evaluation well early in the fourth quarter of 2017, with anticipated production results in the first quarter of 2018. Our current plans, contemplate six evaluations wells in 2018, with two wells targeted for the first half of 2018 and the balance for the second half of 2018.
Given the progress that the Company has made towards establishing a meaningful land position in this early stage, light oil resource play, we will continue to evaluate our Duvernay development plans in the context of the prevailing commodity price environment with a goal towards accelerating our pace of activity, should commodity pricing be supportive.
We are currently evaluating anticipated 2018 capital expenditure levels which is expected to be managed to ensure net debt to trailing FFO does not exceed 1.5 times. The board of directors continuously reviews our long term strategic plan and continues to be supportive of balanced per share growth and new play development while maintaining financial flexibility with our balance sheet.
The business approach taken by the Company since our inception over five years ago, has been to prudently manage our balance sheet while generating and maintaining meaningful per share growth while developing an enviable drilling inventory. Our established Viking drilling inventory of approximately 3,200 locations provides a robust growth and cash flow platform with in excess of 10 years of growth inventory at our current pace of development. In addition to our Viking platform, Raging River’s entrance into the emerging Duvernay light oil play in east central Alberta provides exposure to an exciting early stage opportunity that provides visibility towards additional per share value creation.
Additional corporate information can be found on our website at www.rrexploration.com.
FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. More particularly, this press release contains statements concerning Raging River’s expectations regarding, plans and timing of execution of capital activities, expectations of 2017 exit net debt and expected exit net debt to trailing annualized fourth quarter 2017 FFO ratio, expected 2017 average production, expected capital costs for remainder of 2017, expected average drilling costs for remainder of 2017, expected 2018 operating costs savings, timing of completion of waterflood projects, expected 2017 and 2018 drilling plans including the types of wells to be drilled and specifically drilling plans for the East Duvernay Shale basin, expected future drilling locations, expectation that drilling inventory represents over 10 years of growth and the expectations of the Company’s ability to maintain itself and grow on a per share basis based on different commodity price assumptions. In addition, the use of any of the words “guidance”, “initial, “scheduled”, “can”, “will”, “prior to”, “estimate”, “anticipate”, “believe”, “potential”, “should”, “unaudited”, “forecast”, “future”, “continue”, “may”, “expect”, “project”, and similar expressions are intended to identify forward-looking statements.
The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects the availability of capital, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of existing wells, the performance of new wells, Raging River’s growth strategy, general economic conditions, availability of required equipment and services, prevailing equipment and services costs and prevailing commodity prices. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; as the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Refer to Raging River’s most recent Annual Information Form dated March 6, 2017, on SEDAR at www.sedar.com, and the risk factors contained therein.
The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press
release, as defined by applicable securities legislation, has been approved by management of Raging River as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2017 has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, and represent, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results.
NON-IFRS MEASURES: This document contains the terms “funds flow from operations” (or “FFO”), “net debt”, “field netback”, “operating netback” and “funds flow netback”, which do not have standardized meanings prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable with the calculation of similar measures by other companies. Management uses funds from operations to analyze operating performance and leverage. Management believes “net debt” is a useful supplemental measure of the total amount of current and long-term debt of the Company. Mark-to-market risk management contracts are excluded from the net debt calculation. Management believes “field netback”, “operating netback” and “funds flow netback” are useful supplemental measures of firstly, the amount of revenues received after royalties and operating and transportation costs, secondly, the amount of revenues received after royalties, operating, transportation costs and realized gain (loss) on derivatives, and thirdly, the amount of revenues received after royalties, operating, transportation costs, realized gain (loss) on derivatives, general and administrative costs, financial charges, asset retirement obligations and current taxes. Additional information relating to certain of these non-IFRS measures, including the reconciliation between funds from operations and cash flow from operating activities, can be found in the MD&A.
BARRELS OF OIL EQUIVALENT: The term “boe” or barrels of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.
DRILLING LOCATIONS: This press release discloses future drilling locations. Such drilling locations may be in three different categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company’s most recent independent reserves evaluation as prepared by Sproule as of December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 3,200 drilling locations of the Company identified herein, approximately 1,100 are proved locations, approximately 71 are probable locations and approximately 2,029 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
Mr. Neil Roszell, P. Eng.
CEO and Executive Chairman
403-767-1250
403-387-2951 (FAX)
RAGING RIVER EXPLORATION INC.
Mr. Bruce Beynon, P. Geol.
President
403-767-1251
403-387-2951 (FAX)
RAGING RIVER EXPLORATION INC.
Mr. Jerry Sapieha, CA
Vice President, Finance and Chief Financial Officer
403-767-1265
403-387-2951 (FAX)