FORT WORTH, Texas, Feb. 22, 2017 (GLOBE NEWSWIRE) — RANGE RESOURCES CORPORATION (NYSE:RRC) today announced its 2016 financial results and 2017 capital spending plan.
- Record average daily production of 1.854 Bcfe during the fourth quarter
- 2017 capital budget set at $1.15 billion, projected to provide 33-35% year-over-year growth in 2017 and approximately 20% organic growth in 2018
- North Louisiana well costs reduced to $7.7 million per well from $8.7 million previously
- Fourth quarter 2016 unhedged cash margins improved by over four times to $0.97 per mcfe, compared to $0.22 per mcfe in fourth quarter 2015
- Reserve replacement of 292% at $0.34 per mcfe drill-bit development cost for 2016
Commenting, Jeff Ventura, the Company’s CEO said, “2016 was a significant year for Range, as we completed the acquisition of Memorial Resource Development in September, providing Range operational and geographic diversity with wells that rival our prolific Marcellus wells. In addition, we are beginning to see the advantages of a diversified marketing portfolio, as prices are expected to improve for all products in 2017, driving higher margins and a peer-leading recycle ratio. Higher expected margins and cash flow provide us the opportunity to increase our capital budget to $1.15 billion in 2017, after two consecutive years of declining capital spending. This increased activity in 2017 results in solid growth this year, but also positions us well for 2018 and beyond. With thousands of future locations in our core inventory and talented operational, technical and marketing teams, Range is well-positioned to drive shareholder value for years to come.”
Capital Spending Plans
Range has set its 2017 capital spending budget at $1.15 billion. Approximately two-thirds of the capital budget will be allocated to the Marcellus and one-third to North Louisiana. The budget includes projected service cost increases in 2017, which are expected to be minimal in the Company’s areas of operation. In the Marcellus, approximately 80% of activity will be directed towards liquids-rich drilling, which has a number of advantages. Range’s liquids-rich acreage has an extensive inventory of existing pads that reduce capital costs and gathering expense. The acreage is also in close proximity to capacity for both existing and expected NGL and natural gas takeaway projects, improving netback pricing. Lastly, recent improvements in NGL pricing has bolstered expected drilling returns. Despite shifting capital towards the liquids-rich area, the Company still expects production of approximately 2.07 Bcfe per day in 2017, which equates to absolute growth of 33% to 35% year-over-year. Capital spending in 2017 will also contribute towards production growth of approximately 20% in 2018, expected to be at or near cash flow, assuming a natural gas price of $3.25 per mcf and an oil price of $60.00 per barrel.
The 2017 capital budget includes approximately $1.07 billion for drilling and recompletions (93% of the total), $44 million for leasehold, $22 million for seismic, and $18 million for pipelines, facilities and other. The budget includes 118 wells expected to be brought on line during the year in the Marcellus and 56 wells in North Louisiana. In the Marcellus, approximately one third of the wells are planned to be drilled from existing pads in 2017.
Fourth quarter 2016 drilling expenditures of $195 million funded the drilling of 22 (18.9 net) wells. Drilling expenditures for the year totaled $535 million, and Range drilled 108 (101.9 net) wells during the year. A 100% success rate was achieved. In addition, during 2016, $33 million was spent on acreage purchases, $4 million on gas gathering systems and $30 million on exploration expense. The capital expenditure amounts include North Louisiana expenditures incurred since closing of the merger on September 16, 2016. Drill-bit only finding cost averaged $0.34 per mcfe, including pricing and performance revisions with a reserve replacement ratio of 292%.
Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market adjustment on derivatives, non-cash stock compensation and other items shown separately on the attached tables. “Unit costs” as used in this release are composed of direct operating, transportation, gathering, processing and compression, production and ad valorem taxes, general and administrative, interest and depletion, depreciation and amortization costs divided by production. See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.
Fourth Quarter 2016
GAAP revenues for the fourth quarter of 2016 totaled $254 million (38% decrease compared to fourth quarter 2015), GAAP net cash provided from operating activities including changes in working capital was $185 million (a 5% increase as compared to fourth quarter 2015) and GAAP earnings were a loss of $161 million ($0.66 per diluted share) versus a loss of $322 million ($1.93 per diluted share) in the prior-year quarter. Fourth quarter 2016 results included a $470,000 gain on sale of assets, while 2015 included a loss of $409 million. Fourth quarter 2016 also included $250 million in derivative losses due to increased commodity prices, compared to a $126 million gain in 2015. An $88 million impairment of proved property was also recorded in 2015.
Non-GAAP revenues for fourth quarter 2016 totaled $590 million (30% increase compared to fourth quarter 2015) and cash flow from operations before changes in working capital, a non-GAAP measure, reached $254 million, compared to $204 million in 2015. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $56 million ($0.23 per diluted share) compared to $42 million ($0.25 per diluted share) for the fourth quarter 2015. The Company’s total unit costs were lower than the previous year quarter, with decreases in all categories, except general & administrative and transportation, gathering, processing & compression. General & administrative expenses were higher due to non-recurring land administrative expenses while increased transportation expenses are offset by higher realized prices, as products are moved to more favorable markets.
processing and compression
|Production and ad valorem taxes||0.04||0.06||(33||%)|
|General and administrative||0.26||0.22||18||%|
|Total cash unit costs||1.70||1.66||2||%|
|Depletion, depreciation and
|Total unit costs||$||2.58||$||2.63||(2||%)|
Fourth quarter 2016 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.20 per mcfe, a 1% decrease from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
- Production and realized prices by each commodity for fourth quarter 2016 were: natural gas – 1,244 Mmcf per day ($2.93 per mcf), NGLs – 89,628 barrels per day ($17.20 per barrel) and crude oil and condensate – 12,005 barrels per day ($61.30 per barrel).
- The average Company natural gas price differential including the impact of basis hedges for the fourth quarter was ($0.37) per mcf, which is unchanged from the prior year. The fourth quarter average natural gas price, before all hedging settlements, increased to $2.62 per mcf as compared to $1.90 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations $0.31 per mcf in the fourth quarter of 2016.
- Pre-hedge NGL realizations improved to 29% of West Texas Intermediate (“WTI”) in fourth quarter 2016, compared to 22% of WTI in the previous year. Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging improved to $17.20 for the fourth quarter compared to $11.23 per barrel in the prior year. Hedging increased NGL prices by $2.70 per barrel in the fourth quarter compared to $2.12 per barrel in the prior year.
- Crude oil and condensate price realizations, before realized hedges, for the fourth quarter averaged $44.61 per barrel, or $4.66 below WTI, compared to $13.52 below WTI in the prior year. Hedging added $16.69 per barrel compared to hedge gains of $50.92 in the prior year.
Full Year 2016
GAAP revenues for 2016 totaled $1.1 billion (31% decrease compared to 2015), GAAP net cash provided from operating activities including changes in working capital was $387 million, compared to $691 million in 2015, and GAAP earnings were a loss of $521 million ($2.75 per diluted share) versus a loss of $714 million ($4.29 per diluted share) in 2015. Full year 2016 results included a loss of $7 million from asset sales compared to a loss of $407 million in 2015, $261 million in derivative losses due to increases in future commodity prices compared to a $416 million gain in the prior year and a $43 million impairment of proved property compared to a $590 million impairment of a non-Marcellus property in the prior year.
Non-GAAP revenues for 2016 totaled $1.7 billion, unchanged from 2015 and cash flow from operations before changes in working capital, a non-GAAP measure, was $569 million, compared to $740 million in 2015. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $4.9 million ($0.03 per diluted share), compared to $80 million ($0.48 per diluted share) in 2015. The Company’s cost structure continued to improve as total unit costs decreased by $0.17 per mcfe, or 6%, compared to the prior year, as shown below.
processing and compression
|Production and ad valorem taxes||0.05||0.07||(29||%)|
|General and administrative||0.23||0.27||(15||%)|
|Total cash unit costs||1.75||1.71||2||%|
|Depletion, depreciation and
|Total unit costs||$||2.68||$||2.85||(6||%)|
The Company announced its full year 2016 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates), which averaged $2.74 per mcfe, a 14% decrease from the prior year. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
- Production and realized prices by each commodity for 2016 were: natural gas – 1,027 Mmcf per day ($2.68 per mcf), NGLs – 76,026 barrels per day ($13.16 per barrel) and crude oil and condensate – 9,861 barrels per day ($47.82 per barrel).
- The 2016 average Company natural gas price differential including the impact of basis hedging improved to ($0.45) per mcf compared to ($0.52) per mcf in the prior year. The 2016 average natural gas price, before all hedging settlements, decreased to $2.06 per mcf as compared to $2.13 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations $0.61 per mcf for 2016.
- Pre-hedge NGL realizations improved to 26% of WTI in 2016, compared to 18% of WTI in 2015. Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was $13.15 per barrel compared to $10.73 in the prior year. Hedging increased NGL prices by $1.71 per barrel in 2016 compared to $2.06 in the prior year.
- Crude oil and condensate price realizations, before hedges, for the year averaged $34.60 per barrel, or $9.09 below WTI, compared to $14.93 below WTI in the prior year. Hedging added $13.22 per barrel in 2016, compared to hedge gains of $37.00 per barrel in the prior year.
Range has updated its investor presentation with new economic calculations and type curves for the Marcellus and North Louisiana. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – February 22, 2017”
The table below summarizes the 2016 activity and estimates for 2017 regarding the number of wells to sales, average lateral lengths, well costs, EURs by area and Range’s current net acreage for each area. Consistent with the prior year, updated type curves reflect expected flow restrictions that result from infrastructure and facility design constraints. As a result, early production from prolific wells is often constrained, resulting in flatter decline curves, and is reflected in the type curves. As seen in the presentation slides, Marcellus wells turned in line (“TIL”) over the past three years continue to perform in line with type curve expectations. These results demonstrate the quality of acreage as the Company continues development across its core position in southwest Pennsylvania. Similar data is expected to be provided for North Louisiana drilling results going forward.
|Planned Wells TIL
2017 Lateral Length
|SW PA Super-Rich||14||5,100 ft.||35||8,500 ft.|
|SW PA Wet||30||6,400 ft.||56||8,300 ft.|
|SW PA Dry||46||6,900 ft.||25||8,850 ft.|
|NE PA Dry||19||5,700 ft.||2||6,400 ft.|
|Upper Red||—||34||7,500 ft.|
|Lower Red||—||13||7,500 ft.|
|Total N. LA||3||56|
for 2017 Wells
|Net Acreage by Area
|SW PA Super-Rich||$7.3 million||20.4 Bcfe||110,000|
|SW PA Wet||$6.8 million||24.6 Bcfe||225,000|
|SW PA Dry||$6.1 million||22.3 Bcf||180,000|
|NE PA Dry||$5.0 million||16.0 Bcf||95,000|
|Upper Red||$7.7 million||17.5 Bcfe|
|Lower Red||$7.7 million||11.8 Bcfe|
|Total N. LA||220,000|
Production for the fourth quarter of 2016 averaged approximately 1,419 net Mmcfe per day for both Marcellus Shale divisions, an 11% increase over the prior year. The Southern Marcellus Shale Division averaged 1,235 net Mmcfe per day during the quarter, a 20% increase over the prior year. The Northern Marcellus Shale Division averaged 184 net Mmcf per day during the quarter, a 25% decrease over the prior year, or a 16% decrease over the prior year when adjusted for asset sales.
Southern Marcellus Shale
The Southern Marcellus Shale division brought on line ten wells in the fourth quarter, one in the super-rich area, four in the wet area and five in the dry area. The operated rig count of five has stayed consistent throughout most of the second half of 2016, with three horizontal rigs and two air rigs.
The team continues to look for ways to reduce costs and increase recoveries. Several recent examples are shown below, which have continued to drive lower normalized well costs and reductions in operating costs per mcfe.
- Lateral lengths averaged 6,500 feet in 2016, compared to 6,100 feet in 2015, with projected lateral lengths in 2017 expected to average over 8,000 feet
- Reduced water handling costs in 2016 by over $30 million compared to 2015
- Increased lateral feet drilled per day by 40% compared to the previous year
- Reduced average completion costs per lateral foot by 14% compared to the previous year
- Managed service costs through better utilization rates and long-term vendor relationships
A recent example of what we expect when going back to core areas with longer laterals is a four well pad in the wet area brought on line in the fourth quarter, with an average 9,265 lateral length with 46 stages per well. The average peak 24 hour production rate to sales, under constrained conditions was 35.1 Mmcfe per day per well, roughly twice the average rate of the offset pads. This is a result of refined completion designs, improved landing and longer laterals. On a normalized basis, average cost per well is $651,000 per 1,000 lateral foot with average EUR per well of 3.9 Bcfe per 1,000 lateral foot. On an absolute basis, these wells represent a 47% improvement in recoveries, with an 11% reduction in cost from the average shown on page 35 in the latest investor presentation, with many additional locations expected to produce similar results.
Production for the division in the fourth quarter of 2016, the first full quarter since the Memorial acquisition closing on September 16, 2016, averaged approximately 399 net Mmcfe per day, consisting of 294 Mmcf per day of gas, 13,461 barrels of NGLs per day and 3,998 barrels of condensate per day.
Since acquiring the assets, significant progress has been made operationally, including integration of personnel, information systems, communications systems and facilities. As mentioned on our third quarter conference call, Range has a new drilling team with extensive experience in high-pressure, high-temperature drilling conditions, including experience in the Vernon field. The team has been able to implement significant improvements to date. As a result, total well costs for a typical 7,500 foot lateral well drilled in Terryville have declined from $8.7 million to $7.7 million in just the past five months thereby improving returns and potentially increasing location count. In addition, these cost reductions have occurred while staying within the targeted zone, which has the potential to increase recoveries. The new targeting interval also has been reduced to approximately 30 feet, compared to 90 to 100 feet previously. Updated economics for Upper and Lower Red areas can be found in the Company presentation on slides 40, and 42, showing attractive returns at current strip pricing.
As reported in late January, three wells were drilled and completed in the extension area prior to year-end. The wells were drilled on the north, east and west sides of the Vernon field. Based on logs and cores, the wells to the east and west of Vernon field appear to be structurally similar to Vernon, with multiple, stacked pay zones, and as expected, the over pressured Lower Cotton Valley section thickens when moving south from Terryville. The eastern and western wells each encountered six pay zones with total gas in place of approximately 400 Bcf per square mile, approximately 2.5 times Terryville. Initial production results indicate that each well is expected to have a normalized gas EUR that is in line with Terryville Upper and Lower Red wells. With these encouraging results, Range will continue to analyze well data, observe production characteristics with plans to drill additional extension wells in 2017.
Marketing and Transportation
Range’s overall marketing strategy for many years has been to assemble a diversified low-cost transportation portfolio. Recent developments are proving this to be a good strategy, with net pricing expected to improve on all products in 2017.
Natural gas pricing improved in the fourth quarter, with a full quarter of North Louisiana production and the addition of Spectra’s Gulf Markets project going in-service in early October 2016. The project allows Range to transport 150,000 Mmbtu per day from southwest Pennsylvania to the Gulf Coast, providing a significant improvement to differentials.
Additionally, we have received favorable news regarding FERC authorizations on all remaining Appalachian takeaway projects on which Range holds capacity. Spectra’s Adair Southwest project received its final FERC Certificate in the fourth quarter providing incremental transportation out of the Appalachian basin starting in late 2017. TransCanada’s Leach and Rayne Express projects received their final FERC Certificates in January, with a projected in-service date in late 2017 as well. The combined capacity from these projects for Range is an additional 400,000 Mmbtu per day from the Appalachian Basin to the Gulf Coast, further improving our expected basis differentials. In addition, in early February, FERC approved Energy Transfer’s Rover project. Range has 400,000 Mmbtu/day capacity on the project, with half delivered to Midwest/Canadian markets and half to the Gulf Coast. When combining this capacity with Range’s North Louisiana production, which receives near NYMEX pricing, Range expects its corporate gas differential to improve to approximately $0.30 below NYMEX in 2017. In calculating the differentials, Range assumed only 400,000 Mmbtu per day of capacity would be in-service late 2017.
Range’s gathering and processing costs per mcfe are expected to improve in coming years. In North Louisiana, Range acquired approximately double the processing capacity currently being utilized when the assets were acquired. Range will continue to focus the majority of its activities in the core of the Terryville area which will permit better utilization of our processing commitments in 2017, thereby reducing our minimum volume commitment expenses on a per mcfe basis. In the Marcellus, Range has largely captured the resource and is now going back to existing pads and areas of existing infrastructure, resulting in a downward trend in the Company’s gathering rates per mcfe.
NGL pricing has also improved recently on better domestic market fundamentals and the Company’s strong portfolio of domestic and international sales. As a result, Range’s calculated NGL prices (including ethane and processing costs) for 2017 increased to a range of 28% to 30% of WTI, based on current strip pricing. This approximate 2% increase in realizations would increase pre-hedge NGL revenue by approximately $40 million for the year.
Condensate prices have improved relative to WTI as well. Condensate differentials in the fourth quarter improved to less than $5.00 per barrel, driven largely by the improvement in realizations gained through the addition of Louisiana sales and new Marcellus condensate sales agreements announced in the third quarter. Based on these results, guidance for condensate differentials in 2017 has improved to $5.00 – $6.00 below WTI.
Financial Position and Liquidity
At December 31, 2016, Range had total debt outstanding of $3.81 billion, before debt issuance costs, consisting of $2.88 billion in senior notes, $882 million in bank debt and $49 million in senior subordinated notes. Net debt outstanding, after unamortized debt issuance costs and premiums, equals $3.78 billion.
At December 31, 2016, Range’s bank facility had a borrowing base of $3.0 billion, and bank commitments of $2.0 billion, with an outstanding balance of $882 million and undrawn letters of credit of $261 million, leaving $850 million of borrowing capacity available under the commitment amount.
Guidance – 2017
Production per day Guidance
Production for the first quarter of 2017 is expected to be approximately 1.92 Bcfe per day with 30% to 32% liquids.
Production for the full year 2017 is expected to average approximately 2.07 Bcfe per day. This equates to a year-over-year growth rate of 33% to 35%.
1Q 2017 Expense Guidance
|Direct operating expense:||$0.18 – $0.19 per mcfe|
|Transportation, gathering, processing and compression
|$1.00 – $1.04 per mcfe|
|Production tax expense:||$0.05 – $0.07 per mcfe|
|Exploration expense:||$12.0 – $13.0 million|
|Unproved property impairment expense:||$6.0 – $8.0 million|
|G&A expense:||$0.23 – $0.25 per mcfe|
|Interest expense:||$0.26 – $0.28 per mcfe|
|DD&A expense:||$0.88 – $0.90 per mcfe|
|Net brokered gas marketing expense:||~$2.0 million|
Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in 2017.
|Natural Gas:||NYMEX minus $0.30|
|Natural Gas Liquids (including ethane):||28% – 30% of WTI|
|Oil/Condensate:||WTI minus $5.00 to $6.00|
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has over 75% of its expected 2017 natural gas production hedged at a weighted average floor price of $3.22 per mcf. Similarly, Range has hedged over 60% of its 2017 projected crude oil production at a floor price of $55.81 and approximately 65% of its composite NGL production. Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com.
Range has also hedged Marcellus and other basis differentials to limit volatility between NYMEX and regional prices. The fair value of the basis hedges as of December 31, 2016 was a gain of $11.8 million, compared to a gain of $5.5 million at December 31, 2015.
Conference Call Information
A conference call to review the financial results is scheduled on Thursday, February 23 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 48391940 about 10 minutes prior to the scheduled start time.
A simultaneous webcast of the call may be accessed at www.rangeresources.com. The webcast will be archived for replay on the Company’s website until March 23.