DENVER, July 26, 2017 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported second quarter 2017 financial and operating results. The Company also announced that its wholly owned subsidiary, QEP Energy Company, has entered into a definitive agreement to acquire crude oil and natural gas properties in the Permian Basin for an aggregate purchase price of $732 million, subject to customary purchase price adjustments (the "Acquisition").
SECOND QUARTER 2017 OPERATING HIGHLIGHTS
- Increased average net equivalent production in the Permian Basin to a record 21.2 Mboed
- County Line: completed 16 wells; seven wells being drilled at end of quarter
- Mustang Springs: completed six wells; seven wells waiting on completion; 19 wells being drilled at end of quarter - Increased field level net production to 184.1 MMcfed in the Haynesville, an 83% year-over-year increase as a result of the Company's successful refracturing (refrac) program
2017 PERMIAN BASIN ACQUISITION HIGHLIGHTS
- Adds approximately 13,800 net acres in Martin County, TX, proximate to QEP’s existing Midland Basin acreage
- Over 730 potential horizontal drilling locations over four de-risked horizons
- Adjusted for current production, acquisition cost of less than $1 million per location or approximately $12,800 per net mineral acre per horizon
- Approximately 60% of the identified potential locations can be developed with 10,000 foot or longer laterals
- Nearly all of the acreage is held by production to the Wolfcamp Formation or deeper
- Company estimated net proved reserves of approximately 44 MMBoe and total net recoverable resources of approximately 295 MMBoe - Creates meaningful scale, on a pro forma basis, within the core of the northern Midland Basin
- Approximately 43,000 net acres
- Approximately 1,900 potential horizontal drilling locations, based on current well density assumptions, with further upside from additional horizons and increased well density
"During the second quarter 2017 we made significant progress in the Permian Basin, by increasing drilling activity on our Mustang Springs asset and aggressively developing our County Line asset, resulting in record net equivalent production in the Permian Basin of 21.2 Mboed," commented Chuck Stanley, Chairman, President and CEO of QEP. "Our Haynesville refrac program continues to exceed expectations, with eight new refracs delivering an average gross production rate increase of 16.0 MMcfed per well. Since the inception of the refrac program one year ago, we have increased gross Haynesville production by approximately 146 MMcfed, reaching a peak of nearly 200 MMcfed, its highest level in four years."
"Earlier this week, we announced agreements to sell all of our Pinedale assets and other southwest Wyoming gas assets for a total of $777.5 million, which combined with today’s announced agreement to acquire approximately 13,800 additional net acres in the core of the northern Midland Basin, continues our pivot towards a more oil-focused portfolio. We expect to fund the Permian Basin Acquisition with proceeds from our Pinedale asset sale and with cash on hand. The Pinedale asset sale and the Permian Basin Acquisition will be structured as a like-kind-exchange, and we expect to be able to defer income taxes incurred on the gain on sale."
“The acquisition will significantly expand our Permian Basin net acreage by almost 50% and our potential drilling inventory by over 60% to nearly 1,900 potential horizontal drilling locations, in the core of the northern Midland Basin. We believe the acquisition of this high-quality acreage, which is adjacent and contiguous to our current operations, will considerably enhance our ability to increase our crude oil production in the Permian Basin, improve our operating efficiencies and leverage our solid operational execution.”
The Company has posted to its website www.qepres.com two separate presentations that supplement the information provided in this release.
QEP Second Quarter 2017 Financial Results
The Company reported net income of $45.4 million, or $0.19 per diluted share, for the second quarter 2017 compared with a net loss of $197.0 million, or $0.90 per diluted share, for the second quarter 2016. The increase in net income was primarily due to an increase in unrealized derivative gains, a gain on sale, an increase in average realized prices and a decrease in general and administrative expenses, partially offset by an increase in production and property tax expense and an increase in lease operating expense.
Net income or loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, asset impairments and certain other items. Excluding these items, the Company’s second quarter 2017 Adjusted Net Loss (a non-GAAP measure) was $30.2 million, or $0.12 per diluted share, compared with Adjusted Net Loss of $50.2 million, or $0.23 per diluted share, for the second quarter 2016.
Adjusted EBITDA (a non-GAAP measure) for the second quarter 2017 was $177.2 million compared with $169.1 million for the second quarter 2016, a 5% increase, primarily due to an increase in average realized prices and a decrease in general and administrative expenses, partially offset by decreases in oil and NGL production and increases in production and property taxes and lease operating expenses. The definitions and reconciliations of Adjusted Net Income (Loss) and Adjusted EBITDA to net income (loss) are provided within the financial tables at the end of this release.
Production
Oil equivalent production was 13,860.6 Mboe for the second quarter 2017 compared with 13,882.3 Mboe for the second quarter 2016. Oil and NGL production decreased 7% and 11%, respectively, while natural gas production increased 7%, in the second quarter 2017 compared with the second quarter 2016. Second quarter 2017 oil production declined due to lower production and fewer completions in the Williston Basin partially offset by increased production in the Permian Basin. Second quarter 2017 NGL production declined primarily in Pinedale due to reduced completions activity throughout 2016 and our midstream provider withholding additional volumes to meet linefill requirements. Increased gas production was driven primarily by the Company's successful Haynesville Shale well refrac program partially offset by lower production from Pinedale and the Uinta Basin.
Operating Expenses
During the second quarter 2017, lease operating expense was $5.05 per Boe, transportation and processing costs were $5.21 per Boe, and production and property taxes were $2.06 per Boe. General and administrative expense for the second quarter 2017 was $31.3 million, a decrease of 27% compared with the second quarter 2016, driven primarily by a decrease in in share-based compensation and outside services.
Capital Investment
Capital investment, excluding acquisitions (on an accrual basis), was $306.0 million for the second quarter 2017 compared with $85.7 million for the second quarter 2016, of which $41.5 million was related to midstream infrastructure in the Permian Basin.
QEP also invested $8.4 million to acquire various oil and gas properties, including proved and unproved leasehold and additional surface acreage primarily in the Permian Basin.
Liquidity
Cash and cash equivalents were $178.8 million at the end of the second quarter 2017, and the Company had no borrowings under its unsecured revolving credit facility.
2017 Permian Basin Acquisition
The Company's wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement on July 26, 2017, to acquire crude oil and natural gas properties in the Permian Basin for an aggregate purchase price of $732 million, subject to customary purchase price adjustments. The Company expects to structure the Acquisition as a like-kind-exchange and to fund the Acquisition with the proceeds from the Pinedale Divestiture (discussed below) and cash on hand. The Acquisition is expected to close before the end of October 2017.
The Acquisition properties, located in the core of the northern Midland Basin, consist of approximately 13,800 net acres in Martin County, TX. The Company has identified over 730 potential horizontal drilling locations on the acreage over four horizons - Middle Spraberry, Spraberry Shale, Wolfcamp A and Wolfcamp B - with further upside potential from additional locations in emerging prospective zones and increased well density. The acreage footprint allows for nearly 60% of the identified potential horizontal drilling locations to be developed with 10,000 foot or longer laterals and its proximity to the Company's existing acreage provides opportunities to further optimize lateral length and share existing infrastructure. Nearly all of the Acquisition acreage is held by production to the Wolfcamp Formation or deeper, and the average working interest is 88%, subject to a 25% royalty burden. Current net production from the assets is approximately 635 Boed from 99 vertical wells, of which approximately 71% is crude oil. The Company estimates net proved reserves of approximately 44 MMBoe and total net recoverable resources of approximately 295 MMBoe on the Acquisition properties.
On a pro forma basis, assuming the closing of the acquisition, the Company's Permian Basin position will include approximately 43,000 net acres and approximately 1,900 potential horizontal drilling locations, all located within the core of the northern Midland Basin (excluding acreage in the southern Midland Basin and acreage on the Central Basin Platform).
The 2017 Permian Basin Acquisition presentation provides maps and further details on the Acquisition.
Southwest Wyoming Natural Gas Asset Sales
On July 24, 2017, the Company announced that its wholly owned subsidiary, QEP Energy Company, had entered into two definitive agreements to sell natural gas assets in southwest Wyoming for combined proceeds of $777.5 million, subject to customary purchase price adjustments.
The first agreement provides for the sale of all of QEP’s assets in the Pinedale Anticline field in Sublette County, Wyoming, for a purchase price of $740.0 million (“Pinedale Divestiture”) to Pinedale Energy Partners, LLC, an affiliate of Oak Ridge Natural Resources, LLC. The Pinedale Divestiture includes an estimated 964 Bcfe of proved reserves as of December 31, 2016, and net production in the second quarter 2017 was 218.7 MMcfed, of which approximately 11% was liquids. As part of the Pinedale Divestiture, QEP has agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. The transaction is subject to closing conditions, including regulatory approval, and is expected to close by September 30, 2017.
In a separate transaction, the Company closed the sale of certain non-core natural gas assets in southern Wyoming on June 30, 2017. The purchase price was $37.5 million. The divestiture includes an estimated 15.2 Bcfe of proved reserves as of December 31, 2016, and net production in the second quarter 2017 was approximately 4.3 MMcfed, of which approximately 2% was liquids.
2017 Guidance
The Company’s updated guidance assumes no property acquisitions or divestitures and assumes that QEP will elect to reject ethane from its produced gas for the entire year where QEP has the right to make such an election. The Company intends to adjust its 2017 guidance and 2018 forecasted production following the closing of the Pinedale Divestiture and the Acquisition and in conjunction with its third quarter 2017 earnings release.
QEP's full year 2017 guidance assumes the following updates to the guidance provided on February 22, 2017:
- Addition of one drilling rig in the Permian Basin in July 2017 for the balance of the year
- 10 additional refracs in the Haynesville in 2017 (for a total of approximately 30 refracs in 2017)
- Addition of one drilling rig in the Haynesville in September 2017 for the balance of the year
Slide 5 in the July 2017 Investor Presentation provides additional details on QEP's 2017 Guidance.
| 2017 Guidance Table | ||||||
| 2017 | 2017 | |||||
| Previous Forecast | Current Forecast | |||||
| Oil production (MMbbl) | 21.0 - 22.0 | 21.0 - 22.0 | ||||
| Gas production (Bcf) | 180.0 - 190.0 | 182.5 - 192.5 | ||||
| NGL production (MMbbl) | 5.75 - 6.25 | 5.75 - 6.25 | ||||
| Total oil equivalent production (MMboe) | 57.0 - 60.0 | 57.2 - 60.3 | ||||
| Lease operating and transportation expense (per Boe) | $9.50 - $10.50 | $9.50 - $10.50 | ||||
| Depletion, depreciation and amortization (per Boe) | $16.00 - $17.00 | $15.00 - $16.00 | ||||
| Production and property taxes (% of field-level revenue) | 8.5% | 8.5% | ||||
| (in millions) | ||||||
| General and administrative expense(1) | $160 - $170 | $155 - $165 | ||||
| Capital investment (excluding property acquisitions) | ||||||
| Drilling, Completion and Equip(2) | $890 - $930 | $970 - $1,010 | ||||
| Infrastructure | $50 - $60 | $70 - $80 | ||||
| Corporate | $10 | $10 | ||||
| Total capital investment (excluding property acquisitions) | $950 - $1,000 | $1,050 - $1,100 | ||||
____________________________
(1) General and administrative expense includes approximately $25.0 million of non-cash share-based compensation expense.
(2) Drilling, Completion and Equip includes approximately $20.0 million of non-operated well completion costs.
Operations Summary
The table below presents a summary of QEP-operated and non-operated well completions for the three and six months ended June 30, 2017:
| Operated Completions | Non-operated Completions | ||||||||||||||||||||||
| Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | ||||||||||||||||||||
| June 30, 2017 | June 30, 2017 | June 30, 2017 | June 30, 2017 | ||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
| Northern Region | |||||||||||||||||||||||
| Williston Basin | 8 | 6.4 | 23 | 19.2 | 9 | 0.2 | 14 | 0.3 | |||||||||||||||
| Pinedale | 8 | 4.5 | 8 | 4.5 | — | — | — | — | |||||||||||||||
| Uinta Basin | — | — | — | — | — | — | — | — | |||||||||||||||
| Other Northern | — | — | — | — | — | — | — | — | |||||||||||||||
| Southern Region | |||||||||||||||||||||||
| Permian Basin | 23 | 22.7 | 32 | 31.7 | — | — | — | — | |||||||||||||||
| Haynesville/Cotton Valley | — | — | — | — | — | — | 8 | 0.8 | |||||||||||||||
| Other Southern | — | — | — | — | — | — | — | — | |||||||||||||||
Permian Basin
Permian Basin net production averaged approximately 21.2 Mboed (89% liquids) during the second quarter 2017, a 38% increase compared with the first quarter 2017 and a 23% increase compared with the second quarter 2016 and a record for the Company in the Permian Basin.
QEP completed and turned to sales 23 gross-operated horizontal wells during the quarter, nine wells in late April through early May, and fourteen wells in early to mid-June (average working interest 99%), with 16 on County Line, six on Mustang Springs, and one on the Central Basin Platform.
The 16 wells completed on County Line targeted three horizons - the Leonard Shale (1), Middle Spraberry (6) and Spraberry Shale (9). The Leonard Shale well had a peak 24-hour IP rate of 788 Boed (83% oil) with a lateral length of 7,249 feet. Only two of the six Middle Spraberry wells, drilled at nine wells/mile density, reached peak production in the quarter and had an average peak 24-hour IP of 814 Boed (82% oil) with an average lateral length of 7,342 feet. Similarly, only four of the nine Spraberry Shale wells, drilled at 16 wells/mile density, reached peak rate in the quarter. The four wells had an average peak 24-hour IP of 1,217 Boed (83% oil) with an average lateral length of 7,392 feet.
The six wells completed on Mustang Springs targeted the Wolfcamp A (two wells) and Wolfcamp B (four wells). The two Wolfcamp A wells, drilled at four wells/mile density, reached an average initial flowback rate of 1,215 Boed (89% oil) in the quarter, while the four Wolfcamp B wells, drilled at eight wells/mile density, reached an average initial flowback rate of 1,148 Boed (89% oil). The six wells had an average lateral length of 7,087 feet and represented QEP’s first Wolfcamp density test, the West Pilot, on the Mustang Springs asset. All six Wolfcamp wells were still flowing at the end of the quarter and may not reach peak production until after the installation of artificial lift, which is expected to occur in the third quarter 2017.
The Company continued to implement and refine its tank-style development methodology across its Permian Basin acreage during the quarter. Tank-style development, which targets multiple stacked horizons from a single surface location, is designed to deliver substantial value both above and below ground. Above ground, tank-style development drives both capital and operational efficiencies, including measurable drilling and completion savings and lower production facilities costs, when compared to single-well development. Below ground, the Company is able to maximize production and resource recovery while minimizing offset frac interference and production shut-ins normally associated with infill drilling.
Wells completed with our tank-style development methodology have generated results that have exceeded those of earlier vintage completions, and the Company expects to implement this methodology across all its existing and soon-to-be acquired Permian acreage. The Company believes this approach will become the industry standard for stacked pay development and that the early adoption of this methodology gives the Company a significant competitive advantage in the Basin. (See slide 8 in the July 2017 Investor Presentation for a more detailed overview of the Company's tank-style development.)
QEP completed and turned to sales a second exploration well on its Central Basin Platform Woodford Project in Winkler County, TX during the quarter. The well was drilled to a measured depth of 20,650 feet, with a lateral length of 9,310 feet, and targeted the Woodford Shale. As of the end of the second quarter 2017, the well had been on production for 56 days and reached a peak IP rate of 634 Boed (90% oil). The Company continues to monitor the results of the two exploration wells and expects to make a decision regarding further development plans and the ultimate economic feasibility of this exploration project by the end of the third quarter 2017.
At the end of the second quarter 2017, the Company had seven gross-operated horizontal wells waiting on completion all on Mustang Springs (average working interest 100%), including one in the Spraberry Shale, five in the Middle Spraberry, and one in the Wolfcamp B, and 26 gross-operated horizontal wells being drilled (average working interest 100%), with 19 on Mustang Springs and seven on County Line.
Current QEP-operated drilled and completed authorization for expenditure (AFE) well costs for the Permian Basin are detailed on slide 17 of the July 2017 Investor Presentation.
At the end of the second quarter 2017, the Company had five operated rigs in the Permian Basin, with one on its County Line acreage and four at Mustang Springs.
Slides 6-10 in the July 2017 Investor Presentation depict QEP's acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net production averaged approximately 50.3 Mboed (85% liquids) during the second quarter 2017, a 6% decrease compared with the first quarter 2017 and a 13% decrease compared with the second quarter 2016.
The Company completed and turned to sales eight gross-operated wells during the second quarter, five on South Antelope and three on Ft. Berthold (average working interest 80%). The five wells on South Antelope were in the early stages of flowback at end of the quarter and did not have meaningful production during the quarter. The three wells completed on Ft. Berthold had an average peak 24-hour IP rate of 1,184 Boed (96% oil) with an average lateral length of 9,951 feet. In total, the Company completed nine wells on Ft. Berthold in the first half of 2017. The wells are performing in line with expectations with average peak 24-hour IP of 1,316 Boed (94% oil) with an average lateral length of 10,200 feet. The Company also participated in nine gross non-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 2%).
At the end of the second quarter 2017, QEP had three gross operated wells waiting on completion on South Antelope (average working interest 83%) and three wells being drilled on South Antelope (average working interest 90%).
Current QEP-operated drilled and completed AFE well costs for the Williston Basin are detailed on slide 17 of the July 2017 Investor Presentation.
At the end of the second quarter 2017, the Company had one operated rig in the Williston Basin on South Antelope.
Slides 11-13 the July 2017 Investor Presentation depict QEP's acreage and activity in the Williston Basin.
Haynesville/Cotton Valley
Haynesville/Cotton Valley net production averaged approximately 184.1 MMcfed (30.7 Mboed) (0% liquids) during the second quarter 2017, a 35% increase compared with the first quarter 2017 and an 83% increase compared with the second quarter 2016. The increases were due to the continued success of the ongoing refrac program. During the quarter, the Company completed eight QEP-operated refracs, with an average incremental 24-hour rate increase of 16.0 MMcfed (average working interest 99%).
Current average gross QEP-operated refrac costs are approximately $4.9 million. The Company expects to refrac approximately 30 wells during 2017 (an increase from the approximately 20 refracs originally contemplated for 2017).
At the end of the second quarter, the Company had no rigs operating in the Haynesville/Cotton Valley.
Slides 14-15 the July 2017 Investor Presentation depict QEP's acreage and activity in Haynesville/Cotton Valley.
Pinedale
Pinedale net production averaged approximately 218.7 MMcfed (36.4 Mboed) (11% liquids) during the second quarter 2017, a 7% decrease compared with the first quarter 2017 and a 13% decrease compared with the second quarter 2016. The Company completed and turned to sales eight gross-operated wells during the second quarter 2017 (average working interest 56%).
At the end of the second quarter 2017, the Company had 14 gross-operated Pinedale wells waiting on completion (average working interest 32%) and two wells being drilled (average working interest 20%).
Current average gross QEP-operated drilled and completed AFE well costs are $2.7 million in Pinedale, with costs associated with facilities and plunger lift adding approximately $0.2 million per well. At the end of the second quarter 2017, the Company had one operated rig in Pinedale.
Second Quarter 2017 Results Conference Call
QEP’s management will discuss second quarter 2017 results in a conference call on Thursday, July 27, 2017, beginning at 9:00 a.m. EDT. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website immediately after the call through August 27, 2017, or by dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for international calls, and then entering the conference ID # 13665319. In addition, QEP’s slides for the second quarter 2017, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, can be found on the Company’s website.
About QEP Resources, Inc.
QEP Resources, Inc. (NYSE:QEP) is an independent crude oil and natural gas exploration and production company focused in two regions of the United States: the Northern Region (primarily in North Dakota, Utah and Wyoming) and the Southern Region (primarily in Texas and Louisiana). For more information, visit QEP's' website at: www.qepres.com.
Forward-Looking Statements
This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions. Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include, but are not limited to, statements regarding: forecasted production amounts, lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, production and property taxes, and capital investment, and related assumptions for such guidance; plans to provide adjusted guidance following the closing of the Pinedale Divestiture and the Acquisition; potential drilling locations and related assumptions; our move towards a more oil-focused portfolio; estimated reserves and net recoverable resources; the timing of the closing of each of the Pinedale Divestiture and the Acquisition and related tax-benefits; benefits of the Acquisition, including the enhancement of our ability to expand of our low-cost crude production in the Permian Basin, further improve operating efficiencies and leverage our solid operational execution; implementation and benefits of our tank-style development methodology; structuring and funding of the Acquisition; purchase price adjustments; opportunities in the Permian Basin for shared infrastructure and extended laterals; the timing of the installation of artificial lift in the Permian Basin; the timing of our decision regarding development of the Central Basin Platform Woodford Project; number of refracs in the Haynesville/Cotton Valley; and the usefulness of non-GAAP financial measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: disruptions of QEP's ongoing business, distraction of management and employees, increased expenses and adversely affected results of operations from organizational modifications due to the Pinedale Divestiture and the Acquisition; the inability of the parties to satisfy the conditions to the consummation of such transactions; changes in natural gas, NGL and oil prices; liquidity constraints, including those resulting from the cost or unavailability of financing due to debt and equity capital and credit market conditions, changes in our credit rating, our compliance with loan covenants, the increasing credit pressure on our industry or demands for cash collateral by counterparties to derivative and other contracts; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries; the impact of Brexit; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions, natural resources, and fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal and other proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures; strength of the U.S. dollar; elimination of federal income tax deductions for oil and gas exploration and development; drilling results; shortages of oilfield equipment, services and personnel; the availability of storage and refining capacity; operating risks such as unexpected drilling conditions; transportation constraints; weather conditions; changes in maintenance, service and construction costs; permitting delays; outcome of contingencies such as legal proceedings; inadequate supplies of water and/or lack of water disposal sources; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (the 2016 Annual Report on Form 10-K), and Quarterly Report on Form 10-Q for the quarter ended March 31, 2017. QEP Resources undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
Net Recoverable Resources
The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves calculated in accordance with SEC guidelines; however, QEP has made no such disclosures in its filings with the SEC. “Net recoverable resources” refers to QEP’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and are not proved, probable or possible reserves within the meaning of the rules of the SEC. Probable and possible reserves and net recoverable resources are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially more risks of actually being realized. Actual quantities of natural gas, oil and NGL that may be ultimately recovered from QEP’s interests may differ substantially from the estimates contained in this release due to a number of factors, including: the availability of capital; oil, gas and NGL prices; drilling and production costs; availability of drilling services and equipment; drilling results; geological and mechanical factors affecting recovery rates; lease expirations; transportation constraints; changes in local, regional, national and global demand for natural gas, oil and NGL; changes in, adoption of and compliance with laws and regulations; regulatory approvals; and other factors. Investors are urged to consider carefully the disclosures and risk factors about QEP’s reserves in the 2016 Annual Report on Form 10-K.
| QEP RESOURCES, INC. | |||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||
| (Unaudited) | |||||||||||||||
| Three Months Ended | Six Months Ended | ||||||||||||||
| June 30, | June 30, | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| REVENUES | (in millions, except per share amounts) | ||||||||||||||
| Oil sales | $ | 216.0 | $ | 207.7 | $ | 437.7 | $ | 351.5 | |||||||
| Gas sales | 134.2 | 79.2 | 268.7 | 164.3 | |||||||||||
| NGL sales | 22.8 | 22.8 | 51.8 | 36.4 | |||||||||||
| Other revenue (loss) | 2.7 | (0.5 | ) | 6.7 | 1.8 | ||||||||||
| Purchased oil and gas sales | 8.0 | 24.5 | 38.9 | 41.0 | |||||||||||
| Total Revenues | 383.7 | 333.7 | 803.8 | 595.0 | |||||||||||
| OPERATING EXPENSES | |||||||||||||||
| Purchased oil and gas expense | 9.1 | 26.8 | 38.5 | 43.7 | |||||||||||
| Lease operating expense | 70.0 | 52.6 | 139.2 | 112.6 | |||||||||||
| Transportation and processing costs | 72.2 | 69.5 | 142.4 | 143.1 | |||||||||||
| Gathering and other expense | 1.8 | 1.6 | 3.3 | 2.9 | |||||||||||
| General and administrative | 31.3 | 42.9 | 64.9 | 91.4 | |||||||||||
| Production and property taxes | 28.5 | 20.7 | 57.6 | 38.5 | |||||||||||
| Depreciation, depletion and amortization | 191.5 | 209.7 | 383.3 | 449.7 | |||||||||||
| Exploration expenses | — | 0.4 | 0.4 | 0.7 | |||||||||||
| Impairment | — | 0.8 | 0.1 | 1,183.2 | |||||||||||
| Total Operating Expenses | 404.4 | 425.0 | 829.7 | 2,065.8 | |||||||||||
| Net gain (loss) from asset sales | 19.8 | (0.8 | ) | 19.8 | (0.3 | ) | |||||||||
| OPERATING INCOME (LOSS) | (0.9 | ) | (92.1 | ) | (6.1 | ) | (1,471.1 | ) | |||||||
| Realized and unrealized gains (losses) on derivative contracts | 106.7 | (180.5 | ) | 267.6 | (129.6 | ) | |||||||||
| Interest and other income (expense) | 1.8 | (1.1 | ) | 2.4 | 1.0 | ||||||||||
| Interest expense | (34.9 | ) | (36.6 | ) | (68.7 | ) | (73.3 | ) | |||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 72.7 | (310.3 | ) | 195.2 | (1,673.0 | ) | |||||||||
| Income tax (provision) benefit | (27.3 | ) | 113.3 | (72.9 | ) | 612.2 | |||||||||
| NET INCOME (LOSS) | $ | 45.4 | $ | (197.0 | ) | $ | 122.3 | $ | (1,060.8 | ) | |||||
| Earnings (loss) per common share | |||||||||||||||
| Basic | $ | 0.19 | $ | (0.90 | ) | $ | 0.51 | $ | (5.21 | ) | |||||
| Diluted | $ | 0.19 | $ | (0.90 | ) | $ | 0.51 | $ | (5.21 | ) | |||||
| Weighted-average common shares outstanding | |||||||||||||||
| Used in basic calculation | 240.5 | 217.7 | 240.4 | 203.7 | |||||||||||
| Used in diluted calculation | 240.6 | 217.7 | 240.5 | 203.7 | |||||||||||
| Dividends per common share | $ | — | $ | — | $ | — | $ | — | |||||||
| QEP RESOURCES, INC. | |||||||
| CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||
| (Unaudited) | |||||||
| June 30, 2017 | December 31, 2016 | ||||||
| ASSETS | (in millions) | ||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 178.8 | $ | 443.8 | |||
| Accounts receivable, net | 165.0 | 155.7 | |||||
| Income tax receivable | 12.9 | 18.6 | |||||
| Fair value of derivative contracts | 48.8 | — | |||||
| Hydrocarbon inventories, at lower of average cost or net realizable value | 8.6 | 10.4 | |||||
| Prepaid expenses and other | 10.2 | 11.6 | |||||
| Total Current Assets | 424.3 | 640.1 | |||||
| Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
| Proved properties | 14,840.2 | 14,232.5 | |||||
| Unproved properties | 729.6 | 871.5 | |||||
| Gathering and other | 305.8 | 301.8 | |||||
| Materials and supplies | 39.0 | 32.7 | |||||
| Total Property, Plant and Equipment | 15,914.6 | 15,438.5 | |||||
| Less Accumulated Depreciation, Depletion and Amortization | |||||||
| Exploration and production | 9,069.9 | 8,797.7 | |||||
| Gathering and other | 107.4 | 101.8 | |||||
| Total Accumulated Depreciation, Depletion and Amortization | 9,177.3 | 8,899.5 | |||||
| Net Property, Plant and Equipment | 6,737.3 | 6,539.0 | |||||
| Fair value of derivative contracts | 28.6 | — | |||||
| Other noncurrent assets | 75.3 | 66.3 | |||||
| TOTAL ASSETS | $ | 7,265.5 | $ | 7,245.4 | |||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities | |||||||
| Checks outstanding in excess of cash balances | $ | 11.9 | $ | 12.3 | |||
| Accounts payable and accrued expenses | 305.9 | 269.7 | |||||
| Production and property taxes | 33.0 | 30.1 | |||||
| Interest payable | 32.9 | 32.9 | |||||
| Fair value of derivative contracts | 1.4 | 169.8 | |||||
| Current portion of long-term debt | 134.0 | — | |||||
| Total Current Liabilities | 519.1 | 514.8 | |||||
| Long-term debt | 1,889.0 | 2,020.9 | |||||
| Deferred income taxes | 894.3 | 825.9 | |||||
| Asset retirement obligations | 225.6 | 225.8 | |||||
| Fair value of derivative contracts | 0.1 | 32.0 | |||||
| Other long-term liabilities | 102.4 | 123.3 | |||||
| Commitments and contingencies | |||||||
| EQUITY | |||||||
| Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.2 million and 240.7 million shares issued, respectively | 2.4 | 2.4 | |||||
| Treasury stock – 1.7 million and 1.1 million shares, respectively | (30.3 | ) | (22.9 | ) | |||
| Additional paid-in capital | 1,382.1 | 1,366.6 | |||||
| Retained earnings | 2,295.6 | 2,173.3 | |||||
| Accumulated other comprehensive income (loss) | (14.8 | ) | (16.7 | ) | |||
| Total Common Shareholders' Equity | 3,635.0 | 3,502.7 | |||||
| TOTAL LIABILITIES AND EQUITY | $ | 7,265.5 | $ | 7,245.4 | |||
| QEP RESOURCES, INC. | |||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
| (Unaudited) | |||||||
| Six Months Ended | |||||||
| June 30, | |||||||
| 2017 | 2016 | ||||||
| OPERATING ACTIVITIES | (in millions) | ||||||
| Net income (loss) | $ | 122.3 | $ | (1,060.8 | ) | ||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||
| Depreciation, depletion and amortization | 383.3 | 449.7 | |||||
| Deferred income taxes | 67.2 | (559.9 | ) | ||||
| Impairment | 0.1 | 1,183.2 | |||||
| Bargain purchase gain from acquisition | 0.4 | — | |||||
| Share-based compensation | 7.7 | 19.1 | |||||
| Amortization of debt issuance costs and discounts | 3.1 | 3.2 | |||||
| Net (gain) loss from asset sales | (19.8 | ) | 0.3 | ||||
| Unrealized (gains) losses on marketable securities | (1.4 | ) | (0.5 | ) | |||
| Unrealized (gains) losses on derivative contracts | (277.6 | ) | 243.5 | ||||
| Changes in operating assets and liabilities | 9.9 | (58.2 | ) | ||||
| Net Cash Provided by (Used in) Operating Activities | 295.2 | 219.6 | |||||
| INVESTING ACTIVITIES | |||||||
| Property acquisitions | (76.6 | ) | (23.6 | ) | |||
| Acquisition deposit held in escrow | — | (30.0 | ) | ||||
| Property, plant and equipment, including dry exploratory well expense | (477.9 | ) | (276.6 | ) | |||
| Proceeds from disposition of assets | 2.3 | 23.7 | |||||
| Net Cash Provided by (Used in) Investing Activities | (552.2 | ) | (306.5 | ) | |||
| FINANCING ACTIVITIES | |||||||
| Checks outstanding in excess of cash balances | (0.5 | ) | (29.8 | ) | |||
| Long-term debt issuance costs paid | (1.1 | ) | — | ||||
| Treasury stock repurchases | (6.4 | ) | (3.1 | ) | |||
| Other capital contributions | — | 0.2 | |||||
| Proceeds from issuance of common stock, net | — | 781.6 | |||||
| Excess tax (provision) benefit on share-based compensation | — | 0.2 | |||||
| Net Cash Provided by (Used in) Financing Activities | (8.0 | ) | 749.1 | ||||
| Change in cash and cash equivalents | (265.0 | ) | 662.2 | ||||
| Beginning cash and cash equivalents | 443.8 | 376.1 | |||||
| Ending cash and cash equivalents | $ | 178.8 | $ | 1,038.3 | |||
| Production by Region | |||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
| 2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||
| (in Mboe) | |||||||||||||||||
| Northern Region | |||||||||||||||||
| Williston Basin | 4,573.9 | 5,272.9 | (13 | )% | 9,407.9 | 10,165.5 | (7 | )% | |||||||||
| Pinedale | 3,316.7 | 3,804.9 | (13 | )% | 6,831.6 | 7,997.4 | (15 | )% | |||||||||
| Uinta Basin | 897.0 | 1,311.0 | (32 | )% | 1,865.3 | 2,534.6 | (26 | )% | |||||||||
| Other Northern | 337.1 | 362.4 | (7 | )% | 667.5 | 741.1 | (10 | )% | |||||||||
| Total Northern Region | 9,124.7 | 10,751.2 | (15 | )% | 18,772.3 | 21,438.6 | (12 | )% | |||||||||
| Southern Region | |||||||||||||||||
| Permian Basin | 1,932.1 | 1,578.6 | 22 | % | 3,321.6 | 3,099.9 | 7 | % | |||||||||
| Haynesville/Cotton Valley | 2,792.3 | 1,522.2 | 83 | % | 4,839.0 | 3,045.4 | 59 | % | |||||||||
| Other Southern | 11.5 | 30.3 | (62 | )% | 18.0 | 74.9 | (76 | )% | |||||||||
| Total Southern Region | 4,735.9 | 3,131.1 | 51 | % | 8,178.6 | 6,220.2 | 31 | % | |||||||||
| Total production | 13,860.6 | 13,882.3 | — | % | 26,950.9 | 27,658.8 | (3 | )% | |||||||||
| Total Production | |||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
| 2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||
| Oil (Mbbl) | 4,870.3 | 5,209.5 | (7 | )% | 9,553.0 | 10,385.9 | (8 | )% | |||||||||
| Gas (Bcf) | 45.8 | 42.9 | 7 | % | 88.1 | 86.3 | 2 | % | |||||||||
| NGL (Mbbl) | 1,354.9 | 1,521.3 | (11 | )% | 2,710.3 | 2,886.3 | (6 | )% | |||||||||
| Total production (Mboe) | 13,860.6 | 13,882.3 | — | % | 26,950.9 | 27,658.8 | (3 | )% | |||||||||
| Average daily production (Mboe) | 152.3 | 152.6 | — | % | 148.9 | 152.0 | (2 | )% | |||||||||
| Prices | |||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||
| 2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||||||
| Oil (per bbl) | |||||||||||||||||||||
| Average field-level price | $ | 44.35 | $ | 39.88 | $ | 45.82 | $ | 33.84 | |||||||||||||
| Commodity derivative impact | 2.37 | 3.81 | 0.99 | 5.84 | |||||||||||||||||
| Net realized price | $ | 46.72 | $ | 43.69 | 7 | % | $ | 46.81 | $ | 39.68 | 18 | % | |||||||||
| Gas (per Mcf) | |||||||||||||||||||||
| Average field-level price | $ | 2.93 | $ | 1.84 | $ | 3.05 | $ | 1.90 | |||||||||||||
| Commodity derivative impact | (0.11 | ) | 0.67 | (0.22 | ) | 0.58 | |||||||||||||||
| Net realized price | $ | 2.82 | $ | 2.51 | 12 | % | $ | 2.83 | $ | 2.48 | 14 | % | |||||||||
| NGL (per bbl) | |||||||||||||||||||||
| Average field-level price | $ | 16.86 | $ | 14.97 | $ | 19.11 | $ | 12.61 | |||||||||||||
| Commodity derivative impact | — | — | — | — | |||||||||||||||||
| Net realized price | $ | 16.86 | $ | 14.97 | 13 | % | $ | 19.11 | $ | 12.61 | 52 | % | |||||||||
| Average net equivalent price (per Boe) | |||||||||||||||||||||
| Average field-level price | $ | 26.91 | $ | 22.31 | $ | 28.13 | $ | 19.96 | |||||||||||||
| Commodity derivative impact | 0.46 | 3.51 | (0.36 | ) | 4.02 | ||||||||||||||||
| Net realized price | $ | 27.37 | $ | 25.82 | 6 | % | $ | 27.77 | $ | 23.98 | 16 | % | |||||||||
| Operating Expenses | |||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||
| 2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||||||
| (per Boe) | |||||||||||||||||||||
| Lease operating expense | $ | 5.05 | $ | 3.79 | 33 | % | $ | 5.17 | $ | 4.07 | 27 | % | |||||||||
| Transportation and processing costs | 5.21 | 5.01 | 4 | % | 5.28 | 5.17 | 2 | % | |||||||||||||
| Production and property taxes | 2.06 | 1.48 | 39 | % | 2.14 | 1.39 | 54 | % | |||||||||||||
| Total production costs | $ | 12.32 | $ | 10.28 | 20 | % | $ | 12.59 | $ | 10.63 | 18 | % | |||||||||
QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)
Adjusted EBITDA
This release contains references to the non-GAAP measure of Adjusted EBITDA. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment and certain other items. Management uses Adjusted EBITDA to evaluate QEP's financial performance and trends, make operating decisions and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP's performance from period to period. QEP's Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| (in millions) | |||||||||||||||
| Net income (loss) | $ | 45.4 | $ | (197.0 | ) | $ | 122.3 | $ | (1,060.8 | ) | |||||
| Interest expense | 34.9 | 36.6 | 68.7 | 73.3 | |||||||||||
| Interest and other (income) expense | (1.8 | ) | 1.1 | (2.4 | ) | (1.0 | ) | ||||||||
| Income tax provision (benefit) | 27.3 | (113.3 | ) | 72.9 | (612.2 | ) | |||||||||
| Depreciation, depletion and amortization | 191.5 | 209.7 | 383.3 | 449.7 | |||||||||||
| Unrealized (gains) losses on derivative contracts | (100.3 | ) | 230.0 | (277.6 | ) | 243.5 | |||||||||
| Exploration expenses | — | 0.4 | 0.4 | 0.7 | |||||||||||
| Net (gain) loss from asset sales | (19.8 | ) | 0.8 | (19.8 | ) | 0.3 | |||||||||
| Impairment | — | 0.8 | 0.1 | 1,183.2 | |||||||||||
| Other(1) | — | — | — | 7.7 | |||||||||||
| Adjusted EBITDA | $ | 177.2 | $ | 169.1 | $ | 347.9 | $ | 284.4 | |||||||
____________________________
(1) Reflects legal expenses incurred during the six months ended June 30, 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.
Adjusted Net Income (Loss)
This release also contains references to the non-GAAP measure of Adjusted Net Income (Loss). Management defines Adjusted Net Income (Loss) as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, asset impairments and certain other items. Management uses Adjusted Net Income (Loss) to evaluate QEP’s financial performance and trends, make operating decisions, and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP’s performance from period to period. QEP’s Adjusted Net Income (Loss) may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure) to Adjusted Net Income (Loss). This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| (in millions, except earnings per share) | |||||||||||||||
| Net income (loss) | $ | 45.4 | $ | (197.0 | ) | $ | 122.3 | $ | (1,060.8 | ) | |||||
| Adjustments to net income (loss) | |||||||||||||||
| Unrealized (gains) losses on derivative contracts | (100.3 | ) | 230.0 | (277.6 | ) | 243.5 | |||||||||
| Income taxes on unrealized (gains) losses on derivative contracts(1) | 37.2 | (84.2 | ) | 103.5 | (89.1 | ) | |||||||||
| Net (gain) loss from asset sales | (19.8 | ) | 0.8 | (19.8 | ) | 0.3 | |||||||||
| Income taxes on net (gain) loss from asset sales(1) | 7.3 | (0.3 | ) | 7.4 | (0.1 | ) | |||||||||
| Impairment | — | 0.8 | 0.1 | 1,183.2 | |||||||||||
| Income taxes on impairment(1) | — | (0.3 | ) | — | (433.1 | ) | |||||||||
| Other(2) | — | — | — | 7.7 | |||||||||||
| Income taxes on other(1) | — | — | — | (2.8 | ) | ||||||||||
| Total after tax adjustments to net income | (75.6 | ) | 146.8 | (186.4 | ) | 909.6 | |||||||||
| Adjusted Net Income (Loss) | $ | (30.2 | ) | $ | (50.2 | ) | $ | (64.1 | ) | $ | (151.2 | ) | |||
| Earnings (Loss) per Common Share | |||||||||||||||
| Diluted earnings per share | $ | 0.19 | $ | (0.90 | ) | $ | 0.51 | $ | (5.21 | ) | |||||
| Diluted after-tax adjustments to net income (loss) per share | (0.31 | ) | 0.67 | (0.78 | ) | 4.47 | |||||||||
| Diluted Adjusted Net Income per share | $ | (0.12 | ) | $ | (0.23 | ) | $ | (0.27 | ) | $ | (0.74 | ) | |||
| Weighted-average common shares outstanding | |||||||||||||||
| Diluted | 240.6 | 217.7 | 240.5 | 203.7 | |||||||||||
____________________________
(1) Income tax impact of adjustments is calculated using QEP’s statutory rate of 37.1% and 36.6% for the three months ended June 30, 2017 and 2016, respectively, and QEP's effective tax rate of 37.3% and 36.6% for the six months ended June 30, 2017 and 2016, respectively.
(2) Reflects legal expenses incurred during the six months ended June 30, 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.
The following tables present QEP's volumes and average prices for its open derivative positions as of July 21, 2017:
| Production Commodity Derivative Swaps | |||||||||
| Year | Index | Total Volumes | Average Swap Price per Unit | ||||||
| (in millions) | |||||||||
| Oil sales | (bbls) | ($/bbl) | |||||||
| 2017 | NYMEX WTI | 7.2 | $ | 51.51 | |||||
| 2018 | NYMEX WTI | 10.6 | $ | 53.22 | |||||
| 2019 | NYMEX WTI | 0.4 | $ | 49.75 | |||||
| Gas sales | (MMBtu) | ($/MMBtu) | |||||||
| 2017 | NYMEX HH | 41.3 | $ | 2.87 | |||||
| 2017 | IFNPCR | 13.8 | $ | 2.51 | |||||
| 2018 | NYMEX HH | 98.6 | $ | 2.99 | |||||
| 2019 | NYMEX HH | 3.7 | $ | 2.85 | |||||
| Production Commodity Derivative Gas Collars | |||||||||||||
| Year | Index | Total Volumes | Average Price Floor | Average Price Ceiling | |||||||||
| (in millions) | |||||||||||||
| (MMBtu) | ($/MMBtu) | ($/MMBtu) | |||||||||||
| 2017 | NYMEX HH | 4.6 | $ | 2.50 | $ | 3.50 | |||||||
| Production Commodity Derivative Basis Swaps | |||||||||||
| Year | Index Less Differential | Index | Total Volumes | Weighted-Average Differential | |||||||
| (in millions) | |||||||||||
| Oil sales | (bbls) | ($/bbl) | |||||||||
| 2017 | NYMEX WTI | Argus WTI Midland | 2.2 | $ | (0.67) | ||||||
| 2018 | NYMEX WTI | Argus WTI Midland | 6.2 | $ | (1.09) | ||||||
| 2019 | NYMEX WTI | Argus WTI Midland | 0.4 | $ | (1.10) | ||||||
| Gas sales | (MMBtu) | ($/MMBtu) | |||||||||
| 2017 | NYMEX HH | IFNPCR | 21.4 | $ | (0.18) | ||||||
| 2018 | NYMEX HH | IFNPCR | 7.3 | $ | (0.16) | ||||||
| Storage Commodity Derivative Gas Swaps | |||||||||||
| Year | Type of Contract | Index | Total Volumes | Average Swap Price per Unit | |||||||
| (in millions) | |||||||||||
| Gas sales | (MMBtu) | ($/MMBtu) | |||||||||
| 2017 | SWAP | IFNPCR | 1.1 | $ | 2.83 | ||||||
| Gas purchases | (MMBtu) | ($/MMBtu) | |||||||||
| 2017 | SWAP | IFNPCR | 0.3 | $ | 2.77 | ||||||