Range Announces 6% Increase in Year-End Proved Reserves
Highlights -
- Excluding asset sales of 963 Bcfe, proved reserves increased 6% from year-end 2014
- Range replaced 436% of 2015 production
- Drill-bit finding cost with revisions was
$0.37 per mcfe - Proved developed reserves increased 25% before deducting sales of reserves and production
- Proved developed reserves were 55% of total reserves at year-end 2015, compared to 52% at year-end 2014
- Future development costs for proved undeveloped reserves are
$0.40 per mcfe based on current well costs - Year-end 2015 PV10 value of reserves using future strip prices and current sales contracts was
$6.8 billion comparable to similar year-end 2014 PV10 reserve value of$6.9 billion
Commenting on Range's 2015 proved reserves,
"Our posting, on average, of a modest 0.4 offset proved undeveloped Marcellus drilling locations for each of our proved developed producing wells in the Marcellus demonstrates our ability to grow our
"Importantly, considering all price, performance and reclassification adjustments for the year, Range added over 1.1 Tcfe of reserves with an all-in cost of
SUMMARY OF CHANGES IN PROVED RESERVES | ||||||
(in Bcfe) | ||||||
Balance at December 31, 2014 | 10,310 | |||||
Extensions, discoveries and additions | 1,265 | |||||
Purchases | - | |||||
Performance revisions: | ||||||
PUD improved recovery | 781 | |||||
Performance | 271 | |||||
Total Performance revisions | 1,052 | |||||
Reclassification of PUD to unproved under SEC 5-year rule | (1,167 | ) | ||||
Price revisions | (96 | ) | ||||
Sales of proved reserves | (963 | ) | ||||
Production | (509 | ) | ||||
Balance at December 31, 2015 | 9,892 | |||||
Range replaced 436% of 2015 production from drilling activities including performance and pricing revisions but excluding the PUD reclassification. Drill-bit development costs including performance and pricing revisions were
For 2015, Range added 1,265 Bcfe of proved reserves through the drill-bit, driven by the Company's Marcellus development. The "extensions, discoveries, and additions" amount excludes 781 Bcfe of reserves associated with improved recovery on previously booked, undrilled locations as a result of drilling longer laterals, better lateral targeting and increasing the number of frac stages in the Marcellus which remain in the development plan. The improved recovery estimate is included in the "revision" category rather than "extensions, discoveries and additions" category and represents the incremental increase in recovery including any previous proved undeveloped ("PUD") locations which may have been integrated into longer laterals. On average, the lateral lengths for these proved undeveloped locations are approximately 6,100 feet in the 2015 report compared to 5,370 foot laterals used in the 2014 report. If the improved recovery resulting from the drilling of longer laterals and the increased number of frac stages in the Marcellus were included in the "extensions, discoveries and additions" category because additional capital will be required to capture those incremental reserves than what was previously estimated, the reserve "extensions, discoveries and additions" would total 2,046 Bcfe and the adjusted drill-bit development costs would be
During the year, the Company sold 963 Bcfe of proved reserves (with 761 Bcfe being proved developed reserves) primarily associated with the Nora property sale in
Other changes in reserves during 2015 are comprised of four components. First, as mentioned above, the improved recovery component has a positive revision of 781 Bcfe. Second, field level performance increased by 271 Bcfe due primarily to the continued improvement in the well performance of existing Marcellus producing wells. Third, as a result of lower expected cash flow and our continued success in the Marcellus in drilling longer laterals, the future development plan has been re-optimized which resulted in some previously planned wells not being drilled within five years from their booking date. Range removed from its
Year-end 2015 proved reserves by volume were 64% natural gas, 33% natural gas liquids and 3% crude oil and condensate. Importantly, proved developed producing reserves represents 55% of the Company's reserves a slight increase from 52% at year-end 2014. Correspondingly, the percentage of reserves in the proved undeveloped category at year-end 2015 was 45%, a decrease of 3% from year-end 2014. With our large Marcellus acreage position, Range recorded, on average, a modest 0.4 offset Marcellus drilling locations as proved undeveloped reserves for each of its proved developed producing wells in the play at year-end 2015.
The
Range's unrisked unproved resource potential at year-end 2015, quantifying only the potential Marcellus and Upper Devonian future development, increased to a range of 54 to 70 Tcfe, including 2.9 to 3.8 billion barrels of NGLs and crude oil/condensate. This resource potential does not include any potential for the Utica.
Disclosure Statements:
Certain selected financial information in this release is unaudited. Audited financial results are 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 since 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
Reconciliation of PV-10 ($ in millions) (unaudited) |
|||
December 31, 2015 | |||
Standardized measure of discounted future net of cash flows | $ | 2,726 | |
Discounted future cash flows for income taxes | 303 | ||
Discounted future net cash flows before income taxes (PV-10) | $ | 3,029 | |
Finding and development costs for proved developed reserve additions for the year were
Summary of Changes in Proved Reserves by Category for 2015 | ||||||||||
Proved Developed Reserves | Proved Undeveloped Reserves | Total Proved Reserves |
||||||||
Proved Reserves 12/31/14 (Bcfe) | 5,350 | 4,960 | 10,310 | |||||||
Pro-forma changes (in Bcfe): | ||||||||||
Sales of reserves | (761 | ) | (202 | ) | (963 | ) | ||||
Production | (509 | ) | - | (509 | ) | |||||
Proved Reserves after pro-forma | 4,080 | 4,758 | 8,838 | |||||||
Changes (in Bcfe): | ||||||||||
Extensions, discoveries and additions | 349 | 916 | 1,265 | |||||||
PUDs drilled | 763 | (763 | ) | |||||||
Performance revisions | 321 | 731 | 1,052 | |||||||
5-year rule PUDs reclassified | - | (1,167 | ) | (1,167 | ) | |||||
Pricing revisions | (91 | ) | (5 | ) | (96 | ) | ||||
Changes for year (in Bcfe) | 1,343 | (289 | ) | 1,054 | ||||||
Proved Reserves 12/31/15 (Bcfe) | 5,422 | 4,470 | 9,892 | |||||||
Percent by Category | 55 | % | 45 | % | 100 | % | ||||
Increase in reserves by category * | 18 | % | -6 | % | 6 | % | ||||
* Pro-forma for sales of reserves but deducting production. | ||||||||||
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:
Senior Vice President
817-869-4258
rwaller@rangeresources.com
Vice President - Investor Relations
817-869-4267
lsando@rangeresources.com
Investor Relations Manager
817-869-4266
damend@rangeresources.com
Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
or
Range Media Contact:
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
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