Range Announces 22% Increase in Proved Reserves; Provides Update on Resource Potential and North Louisiana Extension Wells

FORT WORTH, Texas, Jan. 27, 2017 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE:RRC) announced today that proved reserves as of December 31, 2016 were 12.1 Tcfe.    

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, Jeff Ventura, Range’s CEO, said, “Range had another solid year of reserve growth, replacing 292% of production from drilling activities with drill-bit development costs of $0.34 per mcfe when considering pricing and performance revisions.  Positive performance revisions continued in 2016 as we extended laterals, improved targeting and drove efficiencies throughout our developed leasehold and infrastructure.  The strong reserve additions from drilling activity were driven primarily by our development in the Marcellus, as our acquisition of North Louisiana assets closed in late 2016.  Future development costs for proven undeveloped locations are estimated to be $0.42 per mcfe, which is outstanding and should improve our top tier unhedged recycle ratio to over 3x.  Importantly, Range added 1.65 Tcfe of reserves, excluding acquisitions, reflecting our large inventory of low-risk, high- return projects in the Marcellus shale and in North Louisiana.”

“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 $2.2 billion over the next five years, is allocated to proven locations, while the remainder of capital delineates our extensive acreage position, still classified as unproven.  In fact, less than 0.5 offset proven undeveloped locations are currently recorded in the Marcellus and North Louisiana for each horizontal producing well.  We believe this will generate consistent SEC reserve growth over time as additional acreage is classified as proven and capital is allocated to offset locations.  As an example, Range has approximately 740 Bcfe of additional reserves in the Terryville area that would be included as SEC proved reserves if included within the five-year development plan.  Our economic resilience is further demonstrated in the year-end SEC PV₁₀ reserve value of $9.0 billion using future strip prices and current sales contracts.  With 56% of SEC reserves being proved developed (PD), our PD reserve life and debt per PD reserve ratios remain exceptionally strong.”

Range’s estimate of costs incurred during 2016, excluding acquisition costs is approximately $570 million.  This is on target with Range’s previously announced capital budget of $495 million, prior to the Memorial acquisition.

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 Securities and Exchange Commission (“SEC”) proved reserves 269 Bcfe of proved undeveloped reserves that now fall outside the five-year window.  The Company expects these proved undeveloped reserves can be added back in future years as field development continues.  The wells that remain have longer laterals, greater estimated ultimate recoveries (“EURs”) and lower per foot drilling and completion costs which result in expected improved economics.  The resulting corporate proved undeveloped development cost of $0.42 per mcfe is based on 2016 well costs and consists of Marcellus cost of $0.37 per mcfe and North Louisiana cost of $0.68 per mcfe.  Lastly, the lower SEC price for 2016 as compared to 2015 resulted in a minimal downward revision in proved reserves of 23 Bcfe, reflecting the Company’s low-cost reserve base.

During the year, Range sold 165 Bcfe of proved reserves primarily in Oklahoma and non-operated areas in Pennsylvania.

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 Wright & Company, Inc. and were within 1% of the aggregate estimates prepared by Range’s petroleum engineering staff and the Company’s North Louisiana reserves were audited by Netherland, Sewell and Associates, Inc. and were within approximately 2% of Range’s estimates. 

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 Utica, though Range has 400,000 net acres in southwest Pennsylvania. This acreage position has three existing producing wells, one of which is considered a top producer in the play, and multiple operators with offset Utica activity.  As a result, the Company expects to increase its resource potential in Appalachia in the future.  Range’s unrisked unproved resource potential at year-end 2016 for North Louisiana was 6.7 Tcfe, consisting of 670 high-graded drilling locations, based on average lateral lengths of 7,500 feet.  These locations consist of Upper and Lower Red targets, predominantly in the Terryville area.   

North Louisiana Extension Wells

Range has completed three wells in the extension area of North Louisiana, south of Terryville.  These three wells were drilled on the north, east and west sides of the Vernon Field.  Each of the wells encountered significant amounts of gas in multiple zones across the Upper and Lower Red intervals, similar to the prolific Vernon Field that was productive out of both horizons. 

The well to the west of Vernon logged pay in three Upper Red zones that have an estimated 210 Bcf per square mile in place.  The same well logged pay in three zones in the Lower Red with an estimated 188 Bcf per square mile, for a combined total of almost 400 Bcf per square mile.  For reference, this total gas in place is more than 2.5 times Terryville.  The well was completed in one of the Upper Red zones and had an initial flowing pressure of 6,500 psi and a peak constrained 24-hour production rate of 12.4 Mmcf per day. Based on managed cumulative production of 660 Mmcf after 79 days and an effective lateral length of 5,050 feet, the well is expected to have a normalized gas EUR that is in line with Terryville Upper and Lower Red wells. 

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 Vernon field does not have the same amount of production history, though initial production results were below the two other tests.  The well was completed in one of the Lower Red zones and had an initial flowing pressure of 5,600 psi and a peak constrained 24-hour production rate of 5 Mmcf per day.  

Commenting on the results, Jeff Ventura, Range’s CEO, said “Range is very encouraged by the early success the team has had in North Louisiana.  We saw several opportunities to create value when we acquired the assets in late 2016.  The team is already generating value in Terryville through operational improvements that are resulting in significantly lower well costs and improved targeting, which should result in better well performance.  This will remain our focus in North Louisiana for 2017, driving better returns and potentially increasing our drilling inventory throughout the acreage.”    

“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 Lower Cotton Valley pay section thickens as we move towards the Vernon Field, the gas in place increases and there are multiple stacked-pay targets.  While remaining very focused on our core assets in the Marcellus and Terryville, we will look to expand on the initial results from the extension area by methodically testing additional targets throughout this year.”

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 December 31, 2016, which we plan to file with the SEC on February 22, 2017.

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 SEC method of computing finding costs contains additional cost components and results in a higher number.  A reconciliation of the two methods will be shown on the Company’s website at www.rangeresources.com after filing its 2016 Form 10-K.  

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 SEC. We believe that the presentation of pre-tax discounted present value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use pre-tax discounted present value as a basis for comparison of the relative size and value of our reserves as compared with other companies. Range's pre-tax discounted present value as of December 31, 2016 may be reconciled to the GAAP financial measure of its standardized measure of discounted future net cash flows as of December 31, 2016 by reducing Range's pre-tax discounted present value by the discounted future income taxes associated with such reserves. This reconciliation will be included in the Company’s 2016 Form 10-K.

RANGE RESOURCES CORPORATION (NYSE:RRC) is a leading U.S. independent oil and natural gas producer with operations focused in stacked-pay projects in the Appalachian Basin and North Louisiana.  The Company pursues an organic growth strategy targeting high return, low-cost projects within its large inventory of low risk development drilling opportunities. The Company is headquartered in Fort Worth, Texas.  More information about Range can be found at www.rangeresources.com.

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 Securities and Exchange Commission ("SEC"), which are incorporated by reference.

The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves.  Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC.  Range uses certain broader terms such as "resource potential,” or "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines.  Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves.  These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized.  Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers.  Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves.  Area wide unproven resource potential has not been fully risked by Range's management. “EUR,” or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially.  Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors.  Estimates of resource potential may change significantly as development of our resource plays provides additional data.  Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102.  You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.

Range Investor Contacts:

Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com

David Amend, Investor Relations Manager 
817-869-4266
damend@rangeresources.com

Michael Freeman, Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com

Josh 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