Range Announces 22% Increase in Proved Reserves; Provides Update on Resource Potential and North Louisiana Extension Wells
Reserves
Highlights –
- Proved reserves increased 11%, excluding acquisitions and divestitures
- Proved developed reserves increased 14%, excluding acquisitions and divestitures
- Drill-bit development cost with revisions is expected to be
$0.34 per mcfe - Future development costs for proved undeveloped reserves are estimated to be
$0.42 per mcfe; Marcellus costs are estimated to be$0.37 per mcfe - Unhedged recycle ratio improves to over 3x based on future development costs of
$0.42 per mcfe
Commenting on Range’s 2016 proved reserves,
“In North Louisiana, performance in 2016 was in line with our acquisition economics and the properties recorded a slight performance increase, while drilling added 79 Bcfe of reserves post-acquisition. Looking forward, we see capital efficiencies continuing as we drive down well costs while optimizing targeting. Our reserve booking philosophy on the newly acquired assets is consistent with our approach in the Marcellus. As a result, a relatively small portion of the Company’s future development capital, only
Range’s estimate of costs incurred during 2016, excluding acquisition costs is approximately
SUMMARY OF CHANGES IN PROVED RESERVES | |||
(in Bcfe) | |||
Balance at December 31, 2015 | 9,892 | ||
Extensions, discoveries and additions | 1,394 | ||
Purchases | 1,260 | ||
Performance revisions: | |||
PUD improved recovery | 393 | ||
Performance | 154 | ||
Total Performance revisions | 547 | ||
Reclassification of PUD to unproved under SEC 5-year rule | ( 269 | ) | |
Price revisions | (23 | ) | |
Sales of proved reserves | (165 | ) | |
Estimated Production | (564 | ) | |
Balance at December 31, 2016 | 12,072 |
During 2016, Range added 1,394 Bcfe of proved reserves through the drill-bit, driven by 1,315 Bcfe from the Company’s Marcellus development. The “extensions, discoveries, and additions” amount excludes 393 Bcfe of Marcellus reserves associated with undrilled locations that now have increased recovery estimates as a result of longer laterals, better lateral targeting and increased frac stages. This improved recovery estimate is included in the “revision” category. The lateral lengths for existing proved undeveloped locations increased to 7,162 feet in the 2016 report from 6,301 feet in the 2015 report, while newly added proved undeveloped locations in the Marcellus incorporate an average lateral length of approximately 7,900 feet.
To provide more clarity, the 2016 reserve revisions category is segregated into four components. First, as mentioned above, the improved recovery component has a positive revision of 393 Bcfe. Second, field level performance increased reserves by 154 Bcfe due primarily to the continued improvement in the well performance of existing Marcellus producing wells. Third, as a result of Range’s continued success in drilling longer laterals, the future development plan has been re-optimized which results in some previously planned wells not being drilled within five years from their original booking date. Accordingly, Range removed from its
During the year, Range sold 165 Bcfe of proved reserves primarily in Oklahoma and non-operated areas in
Year-end 2016 proved reserves by volume were 65% natural gas, 31% natural gas liquids and 4% crude oil and condensate. Proved developed reserves represents 56% of the Company’s reserves. The Company’s Appalachia reserves were audited by
2016 SEC and Strip Pricing: | ||||||||||||||
2016 Year-End | 2015 Year-End | |||||||||||||
SEC Pricing (a) | Strip Pricing | SEC Pricing (b) | Strip Pricing | |||||||||||
WTI Oil Price ($/Bbl) | $ | 42.68 | $ | 56.49 | $ | 50.13 | $ | 52.14 | ||||||
Natural Gas Price ($/Mmbtu) | $ | 2.48 | $ | 3.14 | $ | 2.59 | $ | 3.25 | ||||||
Proved Reserves PV-10 ($ Billions) | $ | 3.7 | $ | 9.0 | $ | 3.0 | $ | 6.8 | ||||||
(a) SEC benchmark prices adjusted for energy content, quality and basis differentials were $2.07 per Mmbtu, $13.44 per barrel of natural gas liquids and $37.41 per barrel of crude oil, respectively. | ||||||||||||||
(b) SEC benchmark prices adjusted for energy content, quality and basis differentials were $2.07 per Mmbtu, $11.74 per barrel of natural gas liquids and $35.06 per barrel of crude oil, respectively. | ||||||||||||||
Resource Potential
Range’s net unrisked unproved resource potential at year-end 2016, for Appalachia quantifying only the potential Marcellus and Upper Devonian future development, increased to approximately 93 Tcfe, including 4.8 billion barrels of NGLs and crude oil/condensate, consisting of over 4,700 locations in the Marcellus and 2,800 locations in the Upper Devonian, based on average lateral lengths of 8,000 feet. A resource estimate has not yet been provided for the
North Louisiana Extension Wells
Range has completed three wells in the extension area of
The well to the west of
The eastern well also logged pay in three Upper Red zones and three Lower Red zones. The Upper Red zones had a total of 153 Bcf per square mile and the Lower Red totaled 263 Bcf per square mile, for a combined total of over 400 Bcf per square mile. The well was completed in one of the Lower Red zones and had an initial flowing pressure of 6,700 psi and a peak constrained 24-hour production rate of 23.3 Mmcf per day. Based on managed cumulative production of 641 Mmcf after 67 days and an effective lateral length of 4,250 feet, the well also appears to have a normalized gas EUR that is in line with Terryville Upper and Lower Red wells.
The well to the north of
Commenting on the results,
“We also saw the opportunity to create value over time through improved marketing and potentially developing additional horizons within Terryville. In addition we saw long-term potential for development of new fields in the extension areas. The initial production results from outside of Terryville are encouraging. These initial three tests confirm that the
Disclosure Statements:
Certain selected financial information in this release is unaudited. Audited financial results will be provided in our Annual Report on Form 10-K for the year ended
Range has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost – a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. The reserve replacement ratio is calculated by dividing production for the year into the sum of proved extensions, discoveries and additions and proved reserves added by performance revisions or price revisions as stated in each instance in the release. The use of performance revisions is warranted because any adjustment in reserve estimates after the initial estimate of reserves is reflected as a “revision,” even in those instances where the original estimate of reserves was made when the location was classified as proven undeveloped. Any change in the estimate after the well is drilled and reclassified as proved developed would be classified as a “revision.”
Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on estimated and unaudited costs incurred excluding asset retirement obligations, gas gathering facilities and non-cash stock-based compensation and divided by proved reserve additions (extensions, discoveries and additions shown in the table) adjusted for the changes in proved reserves for performance, price and deferral revisions or excluding certain costs such as acreage and acquisitions as stated in each instance in the release. Drill-bit development cost per mcfe is based on estimated and unaudited drilling, development and exploration costs incurred divided by the reserve extensions, discoveries and additions with the inclusion of any revisions as specified in the stated measurement. These calculations do not include the future development costs required for the development of proved undeveloped reserves. The
The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, because the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. These reserves metrics may not be comparable to similarly titled measurements used by other companies.
Year-end pre-tax discounted present value is considered a non-GAAP financial measure as defined by the
Summary of Changes in Proved Reserves by Category for 2016 | ||||||||
Proved Developed Reserves |
Proved Undeveloped Reserves |
Total Proved Reserves |
||||||
(Bcfe) | (Bcfe) | (Bcfe) | ||||||
Proved Reserves 12/31/15 | 5,422 | 4,470 | 9,892 | |||||
Pro-forma changes in reserves: | ||||||||
Extensions, discoveries and additions | 144 | 1,250 | 1,394 | |||||
PUDs drilled | 1,065 | (1,065 | ) | 0 | ||||
Performance revisions | 134 | 413 | 547 | |||||
5-year rule PUDs reclassified | - | (269 | ) | (269 | ) | |||
Pricing revisions | (22 | ) | (1 | ) | (23 | ) | ||
Estimated Production | (564 | ) | 0 | (564 | ) | |||
Proved Reserves after pro-forma | 6,179 | 4,798 | 10,977 | |||||
Purchases | 691 | 569 | 1,260 | |||||
Sales of reserves | (100 | ) | (65 | ) | (165 | ) | ||
Proved Reserves 12/31/16 | 6,770 | 5,302 | 12,072 | |||||
Percent by Category | 56 | % | 44 | % | 100 | % | ||
Increase in reserves by category (a) | 14 | % | 7 | % | 11 | % | ||
Increase in reserves by category | 25 | % | 19 | % | ` | 22 | % | |
(a) Pro-forma change in reserves, which excludes purchase and sale of reserves | ||||||||
All statements, except for statements of historical fact, made in this release, including those relating to substantial coverage ratio, expected lower finding and development costs, estimated current development costs, expected proved undeveloped reserves additions in future years, expected future development plans, estimated future development costs, expected future capital efficiencies, expected rates of return, expected low-risk offsetting potential, expected low-cost strong return project inventory, expected future lateral lengths, expected future strip prices and differentials, improved recovery estimates, future expectation of lower costs, future resource potential, and expected future strong return projects are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and Range's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the
The
Range Investor Contacts:Laith Sando , Vice President – Investor Relations 817-869-4267 lsando@rangeresources.comDavid Amend , Investor Relations Manager 817-869-4266 damend@rangeresources.comMichael Freeman , Senior Financial Analyst 817-869-4264 mfreeman@rangeresources.comJosh Stevens , Financial Analyst 817-869-1564 jrstevens@rangeresources.com or Range Media Contact:Michael Mackin , Director of Public Affairs 724-743-6776 mmackin@rangeresources.com www.rangeresources.com