DENVER, Nov. 07, 2018 (GLOBE NEWSWIRE) — QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported third quarter 2018 financial and operating results and provided an update on its strategic and financial initiatives (Strategic Initiatives) announced in February 2018.
THIRD QUARTER 2018 OPERATING HIGHLIGHTS
- Delivered record quarterly oil and condensate production of 6.6 million barrels (MMbbls), including a record 3.5 MMbbls in the Permian Basin
- Decreased Permian Basin lease operating expense (LOE) to $4.42 per Boe, a 31% year-over-year decrease
- Increased 2018 oil and condensate production guidance to reflect improved efficiencies in the Permian Basin and better than forecasted results in the Williston Basin, despite the loss of production associated with Uinta Basin divestiture
- Increased full year 2018 capital expenditure guidance by 4% at the midpoint to include additional wells drilled and put on production in the Permian Basin as a result of efficiency gains and additional refrac activity in the Williston Basin
- Secured Permian Basin flow assurance, via sales agreements with refiners and marketers, on more than 90% of current and projected gross oil volumes for the remainder of 2018 and for 2019
STRATEGIC INITIATIVES UPDATE
- Entered into a definitive agreement to sell Williston Basin assets for a purchase price of up to $1.725 billion, subject to purchase price adjustments(1)
- Closed the previously announced Uinta Basin divestiture on September 6, 2018 (Uinta Basin Divestiture) for net cash proceeds of $153.0 million, subject to post-closing adjustments
- Continued to progress discussions with interested parties for full divestment of the Company’s Haynesville/Cotton Valley assets
- Received net cash proceeds of $15.7 million from the sale of other non-core assets during the quarter, bringing total net cash proceeds from asset sales, including the Uinta Basin Divestiture, to $217.5 million in 2018
- Reduced headcount by approximately 30% since March 1, 2018 to present, as the Company transitions to a pure-play Permian Basin company
“Our Permian Basin asset delivered Company record oil production volumes for the third consecutive quarter, driven primarily by continued utilization of our ‘tank-style’ development technique, combined with well density optimization and unmatched completion efficiency,” commented Chuck Stanley, Chairman, President and CEO of QEP. “During the quarter, we put four more Permian Basin wells on production than forecast, as we continued to deliver quarter-over-quarter improvements in the pace of new well delivery while driving down costs through industry-leading frac crew efficiency and full utilization of locally sourced proppant. Permian Basin lease operating and gathering and transportation expense also continued to decline as we grew production from horizontal wells, plugged legacy vertical wells and captured operational performance benefits from our full field development.
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(1) The purchase price is comprised of $1.65 billion in cash and contractual rights to receive up to $50 million and $25 million in the buyer’s common stock if the daily volume weighted average trading price of the buyer’s common stock for 10 out of 20 consecutive trading days is at or above $12 per share and $15 per share, respectively. QEP shall be entitled to the equity consideration if the share price thresholds are met at any time during the five year period following closing of the transaction. (See Asset Divestitures discussion in this release for additional details).
“With these operational improvements, we now expect to complete five more wells and put on production approximately 17 wells – three more than forecast – in the Permian in the fourth quarter, with over half of these wells having expected lateral lengths of 9,500 feet or greater,” continued Stanley. “We expect the transition to predominately long laterals, combined with our current four drilling rig and single frac crew program, will support our production profile as we exit 2018 and lay the foundation for 20% – 25% year-over-year Permian Basin oil production growth in 2019.
“Yesterday, we entered into a definitive agreement to sell our Williston Basin assets. The assets have been a significant contributor to the Company for many years and were critical in our pivot towards a more oil-focused portfolio,” continued Stanley. “This transaction marks an important milestone in simplifying our asset portfolio as we continue on our path to becoming a Permian pure-play operator. We intend to use proceeds from asset sales to fund ongoing development of our core Permian assets, reduce debt, and return cash to shareholders through a share repurchase program,” concluded Stanley.
The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release.
QEP Third Quarter 2018 Financial Results
The Company reported net income of $7.3 million, or $0.03 per diluted share, for the third quarter 2018 compared with a net loss of $3.3 million, or $0.01 per diluted share, for the third quarter 2017. The net income in the third quarter 2018 includes a $198.1 million increase in oil and condensate sales due to a 38% increase in oil and condensate production and an 18% increase in average net realized oil prices in the third quarter of 2018 compared to the third quarter of 2017. The increases were partially offset by a $158.3 million decrease in gain from asset sales, inclusive of restructuring costs due to the gain on sale from the divestiture of the Company’s Pinedale assets, which occurred in the third quarter 2017 (Pinedale Divestiture).
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 third quarter 2018 Adjusted Net Income (a non-GAAP measure) was $39.6 million, or $0.17 per diluted share, compared with an Adjusted Net Loss of $23.9 million, or $0.10 per diluted share, for the third quarter 2017.
Adjusted EBITDA (a non-GAAP measure) for the third quarter 2018 was $326.2 million compared with $193.1 million for the third quarter 2017, primarily due to an increase in oil and condensate production, mainly from the Permian Basin, an increase in average net realized oil prices and an increase in gas production in Haynesville/Cotton Valley. The positive impact of these changes on Adjusted EBITDA was partially offset by an increase in realized derivative losses, a decrease in gas sales primarily due to the Pinedale Divestiture and a decrease in average net realized gas prices.
The definitions and reconciliations of Adjusted Net Income (Loss) and Adjusted EBITDA to Net Income (Loss) are provided within Non-GAAP Measures at the end of this release.
Production
Oil equivalent production was 14.4 MMboe for the third quarter 2018 compared with 14.1 MMboe for the third quarter 2017, a 2% increase. Oil and condensate production increased 38%, while natural gas and NGL production decreased 18% and 7%, respectively. Third quarter 2018 equivalent production was positively impacted by increased efficiency of drilling and completion activity in the Permian Basin, which allowed a greater number of wells to be put on production than forecast. These increases were partially offset by decreased production due to the sale of Pinedale, which contributed 3.0 MMboe in the third quarter 2017.
Operating Expenses
During the third quarter 2018, LOE was $64.6 million, a decrease of 15% compared with the third quarter 2017. The decrease in total LOE was primarily due to the Pinedale Divestiture. Excluding Pinedale, LOE decreased $3.3 million, primarily driven by decreases in the Williston Basin and Haynesville/Cotton Valley due to lower workover expense and the Uinta Basin Divestiture, partially offset by increases in the Permian Basin due to the 2017 acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition), and increased power and fuel, maintenance and repairs, and labor expenses.
During the third quarter 2018, LOE was $4.49 per Boe, a decrease of 17% compared with the third quarter 2017, and decreased 28% per Boe excluding the Pinedale Divestiture, primarily due to lower cost production from the 2018 horizontal well completions in the Permian Basin, Williston Basin and Haynesville/Cotton Valley and decreased workover expense in the Williston Basin and Haynesville/Cotton Valley.
Adjusted transportation and processing (T&P) costs (a non-GAAP measure) were $43.8 million during the third quarter 2018, a decrease of 27% compared with the third quarter 2017, primarily due to the Pinedale Divestiture and the Uinta Basin Divestiture. These decreases were partially offset by the recovery of fees in the third quarter 2017 for historical unutilized gathering and transportation capacity in Haynesville/Cotton Valley that was charged to QEP by the operator of wells in which QEP had a working interest and increased production in the third quarter 2018.
During the third quarter 2018, Adjusted T&P costs were $3.04 per Boe, a decrease of 29% compared with the third quarter 2017, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, Adjusted T&P costs per Boe were down 17% due to a decrease in the Permian Basin, partially offset by an increase in Haynesville/Cotton Valley during the third quarter 2018 compared to the third quarter 2017. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts. The cost per Boe increased in Haynesville/Cotton Valley due to the recovery of fees in the third quarter 2017 for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest, partially offset by increased production in the third quarter 2018.
General and administrative (G&A) expense was $48.3 million, or $3.35 per Boe, during the third quarter 2018, an increase of 11% compared with the third quarter 2017. The increase in total G&A expense and G&A expense per Boe in the third quarter 2018 was primarily due to an increase in restructuring costs associated with the implementation of our Strategic Initiatives. In addition to these restructuring-related costs, QEP recognized an increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture and an increase in outside services expenses. These increases in G&A expenses were partially offset by a decrease in legal expenses and loss contingencies and a decrease in share-based compensation and in the mark-to-market value of the deferred compensation wrap plan.
During the third quarter 2018, production and property taxes were $37.4 million, an increase of 31% compared with the third quarter 2017. The increase in production and property taxes was primarily due to higher oil prices and increased oil and condensate production in the Permian and Williston basins, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.
Production and property taxes were $2.60 per Boe, during the third quarter 2018, an increase of 29% compared with the third quarter 2017, but an increase of 27% excluding the Pinedale Divestiture. The 27% increase was due to higher average field-level equivalent prices in the Permian and Williston basins offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe and severance tax exemptions on production from horizontal well development.
Capital Investment
Capital investment, excluding property acquisitions, was $203.7 million (on an accrual basis) for the third quarter 2018, compared with $327.3 million for the third quarter 2017, of which $194.0 million related to the drilling, completion and equipping of wells and $9.1 million was related to infrastructure investment. The decrease in capital expenditures was primarily related to decreased drilling and completion activity in the Permian and Williston basins and Haynesville/Cotton Valley.
During the third quarter 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin, for an aggregate purchase price of $3.2 million.
Asset Divestitures
On November 6, 2018, QEP’s wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement to sell its assets in the Williston Basin to Vantage Acquisition Operating Company, LLC, a wholly-owned subsidiary of Vantage Energy Acquisition Corp. (Nasdaq:VEAC) (“Vantage”) for a purchase price of up to $1.725 billion, subject to purchase price adjustments (Williston Basin Divestiture). The purchase price is comprised of $1.65 billion in cash and contractual rights to receive up to $50.0 million and $25.0 million in Vantage common stock if the daily volume weighted average trading price of Vantage’s common stock for 10 out of 20 consecutive trading days is at or above $12.00 per share and $15.00 per share, respectively. QEP shall be entitled to the equity consideration if the share price thresholds are met at any time during the five year period following closing of the transaction. The agreement provides for the sale of all of QEP’s assets in North Dakota and Montana, which includes the Company’s South Antelope and Fort Berthold leasehold in the Williston Basin. The transaction is subject to certain conditions, including, but not limited to, approval of buyer’s shareholders and regulatory approvals, and is expected to close late in the first quarter or early in the second quarter 2019.
On September 6, 2018, QEP closed on its previously announced divestiture of its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million, subject to customary post-closing adjustments.
In addition to the Uinta Basin Divestiture, QEP closed on the sale of several assets during the third quarter 2018 for total net cash proceeds of approximately $15.7 million.
Liquidity
Net Cash Provided by Operating Activities for the third quarter 2018 was $298.0 million, compared with $186.8 million for the third quarter 2017. Discretionary Cash Flow (a non-GAAP measure) was $291.2 million for the third quarter 2018, compared with $152.4 million for the third quarter 2017. Discretionary Cash Flow in Excess of Capital Expenditures (a non-GAAP measure) was $20.2 million for the third quarter 2018.
The definitions and reconciliations of Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures are provided within Non-GAAP Measures at the end of this release.
As of September 30, 2018, QEP had $375.5 million of borrowings outstanding and $0.3 million in letters of credit outstanding under its revolving credit facility. The Company estimates that, as of September 30, 2018, it could incur additional indebtedness of approximately $1.4 billion and be in compliance with the covenants contained in its revolving credit facility.
Updated 2018 Guidance
The Company’s updated guidance includes no additional adjustment for property acquisitions or divestitures, other than the Uinta Basin Divestiture, which closed in September 2018, and assumes that QEP will elect to recover ethane from its produced gas for the remainder of the year in the Permian Basin where processing economics support ethane recovery.
Impact of Uinta Basin Divestiture on updated production guidance:
• Equivalent production: 0.9 MMboe
- Gas production: 4.3 Bcf
- Oil & condensate production: 0.2 MMbbl
- NGL production: 0.04 MMbbl
QEP’s updated full year 2018 guidance is detailed below.
Rig Count:
• Permian Basin – four rigs and one frac crew in the fourth quarter 2018
Wells Put on Production (full year 2018):
• Company: approximately 121 net operated wells
• Permian Basin: approximately 105 net operated wells
Refracs:
• Four net refracs in the Williston Basin in the fourth quarter 2018
Slide 5 in the November 2018 Investor Presentation provides additional details on QEP’s 2018 Guidance.
| 2018 Guidance | ||||||
| 2018 | 2018 | |||||
| Previous Guidance | Current Guidance | |||||
| Oil & condensate production (MMbbl) | 23.0 – 24.0 | 23.75 – 24.25 | ||||
| Gas production (Bcf) | 137.0 – 143.0 | 136.0 – 140.0 | ||||
| NGL production (MMbbl) | 4.0 – 4.5 | 4.38 – 4.63 | ||||
| Total oil equivalent production (MMboe) | 49.8 – 52.3 | 50.8 – 52.2 | ||||
| Adjusted lease operating and transportation expense (per Boe)(1) | $8.50 – $9.50 | $8.00 – $9.00 | ||||
| Depletion, depreciation and amortization (per Boe) | $17.00 – $18.00 | $16.75 – $17.75 | ||||
| Production and property taxes (% of field-level revenue) | 8.5% | 8.5% | ||||
| (in millions) | ||||||
| General and administrative expense(2) | $205 – $225 | $215 – $225 | ||||
| Capital investment (excluding property acquisitions) | ||||||
| Drilling, Completion and Equip(3) | $1,000 – $1,100 | $1,095 – $1,145 | ||||
| Midstream(4) | $60 | $40 | ||||
| Corporate | $10 | $5 | ||||
| Total capital investment (excluding property acquisitions)(5) | $1,070 – $1,170 | $1,140 – $1,190 | ||||
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(1) Adjusted lease operating and transportation expense (per Boe) is a non-GAAP measure. Refer to Non-GAAP Measures at the end of this release.
(2) General and administrative expense includes approximately $35.0 million of non-cash share-based compensation expense and approximately $35.0 million of estimated restructuring costs.
(3) Approximately 70% of the planned capital investment in Drilling, Completion and Equip is focused on projects in the Permian Basin. Amount includes approximately $20.0 million of non-operated well costs. Includes capital expenditures associated with water sourcing, gathering, recycling and disposal in the Permian Basin.
(4) Includes crude oil and natural gas gathering capital expenditures in the Permian Basin and Haynesville/Cotton Valley.
(5) Increased full year 2018 capital expenditure guidance as a result of improved operational efficiencies, which the Company expects to result in 17 additional net wells being drilled and 10 additional net wells put-on-production, and an increase in the Company’s working interest in acreage acquired through acquisitions and acreage swaps, in the Permian Basin during the year. The increase was partially offset by seven less net refracs put on production in the year than originally forecast.
| Updated 2018 Quarterly Production Guidance(1) | ||||||||
| 1Q 2018 | 2Q 2018 | 3Q 2018 | 3Q 2018 | 4Q 2018 | 2018 | |||
| QEP Resources | Actuals | Actuals | Actuals | Guidance | Current Guidance | |||
| Oil & condensate production (MMbbl) | 5.0 | 6.6 | 6.6 | 6.0 – 6.4 | 5.6 – 6.1 | 23.75 – 24.25 | ||
| Gas production (Bcf) | 35.1 | 38.3 | 38.1 | 34.9 – 37.5 | 24.5 – 28.5 | 136.0 – 140.0 | ||
| NGL production (MMbbl) | 0.9 | 1.2 | 1.4 | 1.1 – 1.2 | 0.90 – 1.15 | 4.38 – 4.63 | ||
| Total oil equivalent production (MMboe) | 11.7 | 14.1 | 14.4 | 12.9 – 13.9 | 10.6 – 12.0 | 50.8 – 52.2 | ||
| Total wells put on production (net) | 35.0 | 47.2 | 22.0 | 18.0 | 17.0 | 121.2 | ||
| Total refracs put on production (net) | 13.7 | 12.8 | 0.1 | — | 4.0 | 30.6 | ||
| Permian Basin | ||||||||
| Oil & condensate production (MMbbl) | 2.2 | 3.2 | 3.5 | 3.0 – 3.3 | 3.3 – 3.6 | 12.2 – 12.5 | ||
| Gas production (Bcf) | 1.9 | 2.1 | 3.3 | 2.4 – 2.6 | 2.9 – 3.1 | 10.2 – 10.4 | ||
| NGL production (MMbbl) | 0.3 | 0.5 | 0.7 | 0.40 – 0.45 | 0.46 – 0.50 | 1.94 – 1.98 | ||
| Permian Basin equivalent production (MMboe) | 2.8 | 4.0 | 4.8 | 3.8 – 4.2 | 4.24 – 4.62 | 15.8 -16.2 | ||
| Permian Basin wells put on production (net) | 31.0 | 36.1 | 21.0 | 17 | 17 | 105.1 | ||
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(1) Quarterly guidance may not add to full year guidance due to significant digit rounding.
Operations Summary
| Permian Basin | Williston Basin | Haynesville/Cotton Valley | |||||||||||||||
| As of September 30, 2018 | |||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Well Progress | |||||||||||||||||
| Drilling | 21 | 21.0 | — | — | — | — | |||||||||||
| At total depth – under drilling rig | — | — | — | — | — | — | |||||||||||
| Waiting to be completed | 16 | 16.0 | — | — | — | — | |||||||||||
| Undergoing completion | 4 | 3.9 | — | — | — | — | |||||||||||
| Completed, awaiting production | 7 | 6.8 | — | — | — | — | |||||||||||
| Waiting on completion | 27 | 26.7 | — | — | — | — | |||||||||||
| Put on production(1) | 21 | 21.0 | — | — | 1 | 1.0 | |||||||||||
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(1) Total operated wells put on production during the three months ended September 30, 2018.
Permian Basin
Permian Basin net oil equivalent production averaged a record of approximately 52.1 Mboed (89% liquids) during the third quarter 2018, an 18% increase compared with the second quarter 2018 and a 104% increase compared with the third quarter 2017. A portion of the increase is driven by higher gas capture rates compared to prior quarters as a result of completion of midstream infrastructure and reduced tie-in activities.
In the third quarter 2018, the Company put on production 21 gross-operated horizontal wells, all on Mustang Springs, four more than forecast for the third quarter 2018 (average working interest 100%). The greater than planned delivery of new producing wells in the third quarter 2018 was a result of a continued increase in drilling and completion efficiency.
At the end of the third quarter 2018, 17 of the 21 wells put on production on Mustang Springs during the quarter were still in the process of cleaning up. The 21 wells were located in three discrete drilling spacing units (DSUs), one with a 31 well/mile density, one with a 24 well/mile density and one with a 23 well/mile density. These three DSUs have “lower than normal” density due to their location on the western edge of the Company’s Mustang Springs acreage position which required certain setbacks and well placement to facilitate ‘tank development’. The four wells that cleaned up reached average peak 24-hour IP of 198 Boed per 1,000 lateral feet (86% oil) from an average lateral length of 7,499 feet.
With regard to the performance of the 37 wells placed on production in the second quarter 2018, which at that time were in various stages of flowback; eight wells on County Line reached average peak 24-hour IP of 150 Boed per 1,000 lateral feet (82% oil) and an average peak 30-day IP of 138 Boed per 1,000 lateral feet (78% oil) from an average lateral length of 7,244 feet. At Mustang Springs, the 29 wells achieved average peak 24-hour IP of 152 Boed per 1,000 feet (85% oil) and an average peak 30-day IP of 118 Boed per 1,000 lateral feet (83% oil) from an average lateral length of 7,430 feet.
During the third quarter 2018, the Company continued to enter into financial derivatives and physical sales agreements for oil production from the Permian Basin. As of the end of the third quarter 2018, 97% of the Company’s approximately 50.0 Mbod of gross field-level oil production was gathered and transported by pipeline. The Company estimates it has flow assurance, via sales agreements with refiners and marketers, on more than 90% of its current and projected gross oil volumes for the remainder of 2018 and 2019. The Company also has 3.0 MMbbls in 2018 and 9.7 MMbbls in 2019 of its projected net oil volumes either covered by basis swaps or sold in markets outside of the Midland Basin. See tables provided at the end of this release for details regarding the Company’s commodity derivative positions.
At the end of the third quarter 2018, the Company had 21 gross-operated horizontal wells in process of being drilled (of which 13 had surface casing set, but had no drilling rig present) (average working interest 100%), no horizontal wells at total depth under drilling rigs, 16 horizontal wells waiting to be completed (average working interest 100%), four horizontal wells undergoing completion (average working interest 98%), and seven fully completed horizontal wells awaiting first production, which were part of a tank “pressure wall” (average working interest 97%).
Current QEP-operated drilled and completed authorization for expenditure (AFE) well costs for the Permian Basin are detailed on slide 21 of the November 2018 Investor Presentation.
At the end of the third quarter 2018, the Company had four operated rigs in the Permian Basin. The Company released one of its operated rigs during mid-July 2018.
Slides 10-14 in the November 2018 Investor Presentation depict QEP’s acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net oil equivalent production averaged approximately 47.6 Mboed (83% liquids) during the third quarter 2018, a 3% decrease compared with the second quarter 2018 and a 3% increase compared with the third quarter 2017.
The Company plans to complete four additional refracs on South Antelope during the remainder of 2018. Current average gross QEP-operated Williston Basin refrac costs are approximately $5.3 million per well.
At the end of the third quarter 2018, the Company had no drilling rigs in the Williston Basin.
Slides 15-17 in the November 2018 Investor Presentation depict QEP’s acreage and activity in the Williston Basin.
Haynesville/Cotton Valley
Haynesville/Cotton Valley net gas equivalent production averaged approximately 296.9 MMcfed (49.5 Mboed) (0% liquids) during the third quarter 2018, a 5% decrease compared with the second quarter 2018 and a 37% increase compared with the third quarter 2017.
The Company put one gross operated well on production during the third quarter 2018 (average working interest 100%). The well had a peak 24-hour IP rate of 34.0 MMcfed (100% gas) with a lateral length of 10,622 feet.
At the end of the third quarter, the Company had no drilling rigs in Haynesville/Cotton Valley.
Slides 18-19 in the November 2018 Investor Presentation depict QEP’s acreage and activity in Haynesville/Cotton Valley.
Third Quarter 2018 Results Conference Call
QEP’s management will discuss third quarter 2018 results in a conference call on Thursday November 8, 2018, beginning at 9:00 a.m. EST. 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 December 8, 2018, 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 # 13683693. In addition, QEP’s slides for the third quarter 2018, 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 with operations in two regions of the United States: the Southern Region (primarily in Texas and Louisiana) and the Northern Region (primarily in North Dakota). 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 statements regarding: transitioning to a pure-play Permian Basin company; number of and reasons for additional wells being completed and put on production in the fourth quarter; total consideration to be received by the Company for the Williston Basin Divestiture; anticipated closing date for and the use of proceeds from the sale of the Williston Basin assets; impact of the Uinta Basin Divestiture on total annual production guidance; the number and location of drilling rigs to be deployed, wells to be put on production and refracs; transitioning to predominantly long laterals with four drilling rigs and a single frac crew; number of new wells having lateral lengths of 9,000 feet or greater; forecast production amounts and growth and related assumptions; forecast adjusted lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, non-cash share-based compensation expense, restructuring costs, production and property taxes, and capital investment for 2018 and related assumptions for such guidance; allocation of capital expenditures; quarterly production guidance and assumptions for such guidance; plans regarding ethane rejection and recovery; the amount of additional indebtedness QEP could incur and be compliance with loan covenants; flow assurance for 95% of QEP’s current and projected gross oil volumes for the remainder of 2018 and 2019; and usefulness of non-GAAP 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: timing and amount of asset divestitures and share repurchases; the occurrence of any event, change or other circumstance that could delay the Williston Basin Divestiture or give rise to the termination of the purchase and sale agreement related thereto; the outcome of any legal proceedings that may be instituted against QEP or Vantage following announcement of the Williston Basin Divestiture; the inability to complete the Williston Basin Divestiture due to the failure to obtain approval of Vantage’s shareholders, or satisfy other conditions to closing in the purchase and sale agreement, including regulatory approval; the risk that the Williston Basin Divestiture disrupts QEP’s current plans and operations as a result of the announcement of the transaction, including the distraction of QEP’s management and employees; costs related to the transaction; changes in applicable laws or regulations; Vantage’s stock price failing to trade above the strike prices; the possibility that Vantage or QEP may be adversely affected by other economic, business and/or competitive factors; changes in oil, gas and NGL 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 QEP’s credit rating, QEP’s compliance with loan covenants, the increasing credit pressure on QEP’s industry or demands for cash collateral by counterparties to derivative and other contracts; market conditions; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural oil, gas and NGL; impact of new laws and regulations, including the use of hydraulic fracture stimulation; impact of U.S. dollar exchange rates on oil, gas and NGL prices; elimination of federal income tax deductions for oil and gas exploration and development; guidance for implementation of the Tax Cuts and Jobs Act; actual proceeds from asset sales; actions of activist shareholders; tariffs on products QEP uses in its operations or sells; 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, including gas and crude oil pipeline takeaway capacity in the Permian Basin; 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; credit worthiness of counterparties to agreements; 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, 2017, and Quarterly Reports on Form 10-Q filed in 2018. QEP 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.
| Contact |
| Investors/Media: |
| William I. Kent, IRC |
| Director, Investor Relations |
| 303-405-6665 |
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| Three Months Ended | Nine Months Ended | ||||||||||||||
| September 30, | September 30, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| REVENUES | (in millions, except per share amounts) | ||||||||||||||
| Oil and condensate, gas and NGL sales | $ | 544.0 | $ | 380.9 | $ | 1,474.1 | $ | 1,139.1 | |||||||
| Other revenue | 3.8 | 3.6 | 11.8 | 10.3 | |||||||||||
| Purchased oil and gas sales | 13.0 | 5.6 | 36.2 | 44.5 | |||||||||||
| Total Revenues | 560.8 | 390.1 | 1,522.1 | 1,193.9 | |||||||||||
| OPERATING EXPENSES | |||||||||||||||
| Purchased oil and gas expense | 13.3 | 6.9 | 38.6 | 45.4 | |||||||||||
| Lease operating expense | 64.6 | 76.2 | 203.6 | 215.4 | |||||||||||
| Transportation and processing costs | 28.0 | 60.2 | 93.2 | 202.6 | |||||||||||
| Gathering and other expense | 4.6 | 1.7 | 10.8 | 5.0 | |||||||||||
| General and administrative | 48.3 | 43.4 | 164.2 | 108.3 | |||||||||||
| Production and property taxes | 37.4 | 28.5 | 103.9 | 86.1 | |||||||||||
| Depreciation, depletion and amortization | 234.9 | 176.9 | 673.6 | 560.2 | |||||||||||
| Exploration expenses | — | 21.3 | 0.1 | 21.7 | |||||||||||
| Impairment | — | 28.3 | 404.4 | 28.4 | |||||||||||
| Total Operating Expenses | 431.1 | 443.4 | 1,692.4 | 1,273.1 | |||||||||||
| Net gain (loss) from asset sales, inclusive of restructuring costs | 27.1 | 185.4 | 26.7 | 205.2 | |||||||||||
| OPERATING INCOME (LOSS) | 156.8 | 132.1 | (143.6 | ) | 126.0 | ||||||||||
| Realized and unrealized gains (losses) on derivative contracts | (108.0 | ) | (104.3 | ) | (240.3 | ) | 163.3 | ||||||||
| Interest and other income (expense) | (0.3 | ) | 0.1 | (4.1 | ) | 2.5 | |||||||||
| Interest expense | (38.7 | ) | (34.4 | ) | (111.9 | ) | (103.1 | ) | |||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 9.8 | (6.5 | ) | (499.9 | ) | 188.7 | |||||||||
| Income tax (provision) benefit | (2.5 | ) | 3.2 | 117.6 | (69.7 | ) | |||||||||
| NET INCOME (LOSS) | $ | 7.3 | $ | (3.3 | ) | $ | (382.3 | ) | $ | 119.0 | |||||
| Earnings (loss) per common share | |||||||||||||||
| Basic | $ | 0.03 | $ | (0.01 | ) | $ | (1.60 | ) | $ | 0.49 | |||||
| Diluted | $ | 0.03 | $ | (0.01 | ) | $ | (1.60 | ) | $ | 0.49 | |||||
| Weighted-average common shares outstanding | |||||||||||||||
| Used in basic calculation | 236.9 | 240.7 | 238.3 | 240.5 | |||||||||||
| Used in diluted calculation | 237.0 | 240.7 | 238.3 | 240.5 | |||||||||||
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
| September 30, 2018 |
December 31, 2017 |
||||||
| ASSETS | (in millions) | ||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Accounts receivable, net | 191.7 | 141.8 | |||||
| Income tax receivable | 4.1 | 4.9 | |||||
| Fair value of derivative contracts | 14.0 | 3.4 | |||||
| Prepaid expenses | 11.4 | 10.1 | |||||
| Other current assets | 0.2 | 4.3 | |||||
| Total Current Assets | 221.4 | 164.5 | |||||
| Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
| Proved properties | 11,717.8 | 11,873.6 | |||||
| Unproved properties | 1,034.4 | 1,086.4 | |||||
| Gathering and other | 369.6 | 318.7 | |||||
| Materials and supplies | 37.3 | 32.9 | |||||
| Total Property, Plant and Equipment | 13,159.1 | 13,311.6 | |||||
| Less Accumulated Depreciation, Depletion and Amortization | |||||||
| Exploration and production | 6,160.3 | 6,642.9 | |||||
| Gathering and other | 121.4 | 124.3 | |||||
| Total Accumulated Depreciation, Depletion and Amortization | 6,281.7 | 6,767.2 | |||||
| Net Property, Plant and Equipment | 6,877.4 | 6,544.4 | |||||
| Fair value of derivative contracts | 0.1 | 0.1 | |||||
| Other noncurrent assets | 58.3 | 53.0 | |||||
| Noncurrent assets held for sale | — | $ | 632.8 | ||||
| TOTAL ASSETS | $ | 7,157.2 | $ | 7,394.8 | |||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities | |||||||
| Checks outstanding in excess of cash balances | $ | 15.3 | $ | 44.0 | |||
| Accounts payable and accrued expenses | 335.6 | 363.8 | |||||
| Production and property taxes | 40.9 | 31.6 | |||||
| Interest payable | 33.1 | 26.0 | |||||
| Fair value of derivative contracts | 200.7 | 103.6 | |||||
| Asset retirement obligations | 5.0 | 3.5 | |||||
| Total Current Liabilities | 630.6 | 572.5 | |||||
| Long-term debt | 2,451.1 | 2,160.8 | |||||
| Deferred income taxes | 398.8 | 518.0 | |||||
| Asset retirement obligations | 155.5 | 159.0 | |||||
| Fair value of derivative contracts | 52.6 | 31.8 | |||||
| Other long-term liabilities | 93.7 | 102.2 | |||||
| Other long-term liabilities held for sale | — | 52.6 | |||||
| Commitments and contingencies | |||||||
| EQUITY | |||||||
| Common stock – par value $0.01 per share; 500.0 million shares authorized; 239.8 million and 243.0 million shares issued, respectively | 2.4 | 2.4 | |||||
| Treasury stock – 3.0 million and 2.0 million shares, respectively | (44.2 | ) | (34.2 | ) | |||
| Additional paid-in capital | 1,424.6 | 1,398.2 | |||||
| Retained earnings | 2,002.0 | 2,442.6 | |||||
| Accumulated other comprehensive income (loss) | (9.9 | ) | (11.1 | ) | |||
| Total Common Shareholders’ Equity | 3,374.9 | 3,797.9 | |||||
| TOTAL LIABILITIES AND EQUITY | $ | 7,157.2 | $ | 7,394.8 | |||
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| Three Months Ended | Nine Months Ended | ||||||||||||||
| September 30, | September 30, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| OPERATING ACTIVITIES | (in millions) | ||||||||||||||
| Net income (loss) | $ | 7.3 | $ | (3.3 | ) | $ | (382.3 | ) | $ | 119.0 | |||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||||||||||
| Depreciation, depletion and amortization | 234.9 | 176.9 | 673.6 | 560.2 | |||||||||||
| Deferred income taxes (benefit) | 0.9 | 1.3 | (119.6 | ) | 68.5 | ||||||||||
| Impairment | — | 28.3 | 404.4 | 28.4 | |||||||||||
| Dry hole exploratory well expense | — | 21.2 | — | 21.2 | |||||||||||
| Share-based compensation | 4.9 | 5.8 | 28.3 | 13.5 | |||||||||||
| Amortization of debt issuance costs and discounts | 1.4 | 1.7 | 4.0 | 4.8 | |||||||||||
| Bargain purchase gain from acquisition | — | — | — | 0.4 | |||||||||||
| Net (gain) loss from asset sales, inclusive of restructuring costs | (27.1 | ) | (185.4 | ) | (26.7 | ) | (205.2 | ) | |||||||
| Unrealized (gains) losses on marketable securities | (0.7 | ) | (0.7 | ) | (1.1 | ) | (2.1 | ) | |||||||
| Unrealized (gains) losses on derivative contracts | 69.6 | 116.0 | 113.2 | (161.6 | ) | ||||||||||
| Other non-cash activity | — | (9.4 | ) | — | (9.4 | ) | |||||||||
| Changes in operating assets and liabilities | 6.8 | 34.4 | (18.9 | ) | 45.1 | ||||||||||
| Net Cash Provided by (Used in) Operating Activities | 298.0 | 186.8 | 674.9 | 482.8 | |||||||||||
| INVESTING ACTIVITIES | |||||||||||||||
| Property acquisitions | (3.2 | ) | (17.9 | ) | (48.3 | ) | (94.5 | ) | |||||||
| Property, plant and equipment, including exploratory well expense | (267.8 | ) | (301.7 | ) | (1,032.1 | ) | (779.6 | ) | |||||||
| Proceeds from disposition of assets | 168.7 | 785.6 | 217.5 | 787.9 | |||||||||||
| Net Cash Provided by (Used in) Investing Activities | (102.3 | ) | 466.0 | (862.9 | ) | (86.2 | ) | ||||||||
| FINANCING ACTIVITIES | |||||||||||||||
| Checks outstanding in excess of cash balances | 6.8 | (11.8 | ) | (28.7 | ) | (12.3 | ) | ||||||||
| Long-term debt issuance costs paid | (0.1 | ) | — | (0.1 | ) | (1.1 | ) | ||||||||
| Proceeds from credit facility | 586.5 | 2.0 | 2,616.0 | 2.0 | |||||||||||
| Repayments of credit facility | (786.0 | ) | (2.0 | ) | (2,329.5 | ) | (2.0 | ) | |||||||
| Common stock repurchased and retired | — | — | (58.4 | ) | — | ||||||||||
| Treasury stock repurchases | (1.9 | ) | (0.4 | ) | (7.8 | ) | (6.8 | ) | |||||||
| Other capital contributions | 0.1 | — | 0.3 | — | |||||||||||
| Net Cash Provided by (Used in) Financing Activities | (194.6 | ) | (12.2 | ) | 191.8 | (20.2 | ) | ||||||||
| Change in cash, cash equivalents and restricted cash | 1.1 | 640.6 | 3.8 | 376.4 | |||||||||||
| Beginning cash, cash equivalents and restricted cash | 26.1 | 201.2 | 23.4 | 465.4 | |||||||||||
| Ending cash, cash equivalents and restricted cash | $ | 27.2 | $ | 841.8 | $ | 27.2 | $ | 841.8 | |||||||
| Production by Region | |||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
| 2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||
| (in Mboe) | |||||||||||||||||
| Northern Region | |||||||||||||||||
| Williston Basin | 4,381.1 | 4,252.3 | 3 | % | 12,570.5 | 13,660.2 | (8 | )% | |||||||||
| Pinedale | — | 3,010.8 | (100 | )% | 0.1 | 9,842.4 | (100 | )% | |||||||||
| Uinta Basin | 606.0 | 905.3 | (33 | )% | 2,232.2 | 2,770.6 | (19 | )% | |||||||||
| Other Northern | 63.1 | 278.1 | (77 | )% | 211.3 | 945.6 | (78 | )% | |||||||||
| Total Northern Region | 5,050.2 | 8,446.5 | (40 | )% | 15,014.1 | 27,218.8 | (45 | )% | |||||||||
| Southern Region | |||||||||||||||||
| Permian Basin | 4,792.5 | 2,351.3 | 104 | % | 11,591.6 | 5,672.9 | 104 | % | |||||||||
| Haynesville/Cotton Valley | 4,552.8 | 3,321.2 | 37 | % | 13,604.6 | 8,160.2 | 67 | % | |||||||||
| Other Southern | 4.5 | 5.1 | (12 | )% | 20.4 | 23.1 | (12 | )% | |||||||||
| Total Southern Region | 9,349.8 | 5,677.6 | 65 | % | 25,216.6 | 13,856.2 | 82 | % | |||||||||
| Total production | 14,400.0 | 14,124.1 | 2 | % | 40,230.7 | 41,075.0 | (2 | )% | |||||||||
| Total Production | |||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
| 2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||
| Oil and condensate (Mbbl) | 6,640.5 | 4,827.1 | 38 | % | 18,182.1 | 14,380.1 | 26 | % | |||||||||
| Gas (Bcf) | 38.1 | 46.7 | (18 | )% | 111.5 | 134.8 | (17 | )% | |||||||||
| NGL (Mbbl) | 1,415.3 | 1,516.1 | (7 | )% | 3,472.5 | 4,226.4 | (18 | )% | |||||||||
| Total production (Mboe) | 14,400.0 | 14,124.1 | 2 | % | 40,230.7 | 41,075.0 | (2 | )% | |||||||||
| Average daily production (Mboe) | 156.5 | 153.5 | 2 | % | 147.4 | 150.5 | (2 | )% | |||||||||
| Prices | |||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| 2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||
| Oil (per bbl) | |||||||||||||||||||||
| Average field-level price | $ | 62.65 | $ | 45.16 | $ | 61.89 | $ | 45.60 | |||||||||||||
| Commodity derivative impact | (6.27 | ) | 2.51 | (7.59 | ) | 1.50 | |||||||||||||||
| Net realized price | $ | 56.38 | $ | 47.67 | 18 | % | $ | 54.30 | $ | 47.10 | 15 | % | |||||||||
| Gas (per Mcf) | |||||||||||||||||||||
| Average field-level price | $ | 2.67 | $ | 2.80 | $ | 2.71 | $ | 2.96 | |||||||||||||
| Commodity derivative impact | 0.09 | (0.01 | ) | 0.10 | (0.15 | ) | |||||||||||||||
| Net realized price | $ | 2.76 | $ | 2.79 | (1 | )% | $ | 2.81 | $ | 2.81 | — | % | |||||||||
| NGL (per bbl) | |||||||||||||||||||||
| Average field-level price | $ | 29.65 | $ | 21.28 | $ | 25.39 | $ | 19.89 | |||||||||||||
| Commodity derivative impact | — | — | — | — | |||||||||||||||||
| Net realized price | $ | 29.65 | $ | 21.28 | 39 | % | $ | 25.39 | $ | 19.89 | 28 | % | |||||||||
| Average net equivalent price (per Boe) | |||||||||||||||||||||
| Average field-level price | $ | 38.87 | $ | 26.97 | $ | 37.66 | $ | 27.73 | |||||||||||||
| Commodity derivative impact | (2.66 | ) | 0.83 | (3.16 | ) | 0.05 | |||||||||||||||
| Net realized price | $ | 36.21 | $ | 27.80 | 30 | % | $ | 34.50 | $ | 27.78 | 24 | % | |||||||||
| Operating Expenses | |||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| 2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||
| (in millions) | |||||||||||||||||||||
| Lease operating expense | $ | 64.6 | $ | 76.2 | (15 | )% | $ | 203.6 | $ | 215.4 | (5 | )% | |||||||||
| Adjusted transportation and processing costs(1) | 43.8 | 60.2 | (27 | )% | 134.1 | 202.6 | (34 | )% | |||||||||||||
| Production and property taxes | 37.4 | 28.5 | 31 | % | 103.9 | 86.1 | 21 | % | |||||||||||||
| $ | 145.8 | $ | 164.9 | (12 | )% | $ | 441.6 | $ | 504.1 | (12 | )% | ||||||||||
| (per Boe) | |||||||||||||||||||||
| Lease operating expense | $ | 4.49 | $ | 5.39 | (17 | )% | $ | 5.06 | $ | 5.24 | (3 | )% | |||||||||
| Adjusted transportation and processing costs(1) | 3.04 | 4.26 | (29 | )% | 3.34 | 4.93 | (32 | )% | |||||||||||||
| Production and property taxes | 2.60 | 2.02 | 29 | % | 2.58 | 2.10 | 23 | % | |||||||||||||
| Total production costs | $ | 10.13 | $ | 11.67 | (13 | )% | $ | 10.98 | $ | 12.27 | (11 | )% | |||||||||
____________________________
(1) Adjusted transportation and processing costs is a non-GAAP measure. The definition and reconciliation of adjusted transportation and processing costs to transportation and processing costs, as presented, are provided within Non-GAAP Measures at the end of this release.
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 measure prepared in accordance with GAAP.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| September 30, | September 30, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| (in millions) | |||||||||||||||
| Net income (loss) | $ | 7.3 | $ | (3.3 | ) | $ | (382.3 | ) | $ | 119.0 | |||||
| Interest expense | 38.7 | 34.4 | 111.9 | 103.1 | |||||||||||
| Interest and other (income) expense | 0.3 | (0.1 | ) | 4.1 | (2.5 | ) | |||||||||
| Income tax provision (benefit) | 2.5 | (3.2 | ) | (117.6 | ) | 69.7 | |||||||||
| Depreciation, depletion and amortization | 234.9 | 176.9 | 673.6 | 560.2 | |||||||||||
| Unrealized (gains) losses on derivative contracts | 69.6 | 116.0 | 113.2 | (161.6 | ) | ||||||||||
| Exploration expenses | — | 21.3 | 0.1 | 21.7 | |||||||||||
| Net (gain) loss from asset sales, inclusive of restructuring costs | (27.1 | ) | (185.4 | ) | (26.7 | ) | (205.2 | ) | |||||||
| Impairment | — | 28.3 | 404.4 | 28.4 | |||||||||||
| Other(1) | — | 8.2 | — | 8.2 | |||||||||||
| Adjusted EBITDA | $ | 326.2 | $ | 193.1 | $ | 780.7 | $ | 541.0 | |||||||
____________________________
(1) Reflects legal expenses and loss contingencies incurred during the three and nine months ended September 30, 2017. 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 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 measure prepared in accordance with GAAP.
| Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| (in millions, except earnings per share) | |||||||||||||||
| Net income (loss) | $ | 7.3 | $ | (3.3 | ) | $ | (382.3 | ) | $ | 119.0 | |||||
| Adjustments to net income (loss) | |||||||||||||||
| Unrealized (gains) losses on derivative contracts | 69.6 | 116.0 | 113.2 | (161.6 | ) | ||||||||||
| Income taxes on unrealized (gains) losses on derivative contracts(1) | (16.6 | ) | (43.0 | ) | (26.6 | ) | 59.6 | ||||||||
| Net (gain) loss from asset sales, inclusive of restructuring costs | (27.1 | ) | (185.4 | ) | (26.7 | ) | (205.2 | ) | |||||||
| Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs(1) | 6.4 | 68.8 | 6.3 | 75.7 | |||||||||||
| Impairment | — | 28.3 | 404.4 | 28.4 | |||||||||||
| Income taxes on impairment(1) | — | (10.5 | ) | (95.0 | ) | (10.5 | ) | ||||||||
| Other(2) | — | 8.2 | — | 8.2 | |||||||||||
| Income taxes on other(1) | — | (3.0 | ) | — | (3.0 | ) | |||||||||
| Total after tax adjustments to net income | 32.3 | (20.6 | ) | 375.6 | (208.4 | ) | |||||||||
| Adjusted Net Income (Loss) | $ | 39.6 | $ | (23.9 | ) | $ | (6.7 | ) | $ | (89.4 | ) | ||||
| Earnings (Loss) per Common Share | |||||||||||||||
| Diluted earnings per share | $ | 0.03 | $ | (0.01 | ) | $ | (1.60 | ) | $ | 0.49 | |||||
| Diluted after-tax adjustments to net income (loss) per share | 0.14 | (0.09 | ) | 1.58 | (0.87 | ) | |||||||||
| Diluted Adjusted Net Income per share | $ | 0.17 | $ | (0.10 | ) | $ | (0.02 | ) | $ | (0.38 | ) | ||||
| Weighted-average common shares outstanding | |||||||||||||||
| Diluted | 237.0 | 240.7 | 238.3 | 240.5 | |||||||||||
____________________________
(1) Income tax impact of adjustments is calculated using QEP’s statutory rate of 23.8% and 37.1% for the three months ended September 30, 2018 and 2017, respectively and QEP’s effective tax rate of 23.5% and 36.9% for the nine months ended September 30, 2018 and 2017, respectively.
(2) Reflects legal expenses and loss contingencies incurred during the three and nine months ended September 30, 2017. 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 Net Income.
Adjusted Transportation and Processing Costs
This release contains references to the non-GAAP measure of adjusted transportation and processing costs. Management defines adjusted transportation and processing costs as transportation and processing costs presented on the Condensed Consolidated Statements of Operations and transportation and processing costs that are included as part of “Oil and condensate, gas and NGL sales” on the Condensed Consolidated Statements of Operations. These costs are added together to reflect the total operating costs associated with QEP’s production. Management believes that this non-GAAP measure is useful supplemental information for investors as it reflects the total production costs required to operate the wells for the period and is a more comparable measure to the operating costs of its peers.
Below is a reconciliation of adjusted transportation and processing costs to transportation and processing costs as presented on the Condensed Consolidated Statements of Operations (a GAAP measure). This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial measure prepared in accordance with GAAP.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Adjusted transportation and processing costs | $ | 43.8 | $ | 60.2 | $ | (16.4 | ) | $ | 134.1 | $ | 202.6 | $ | (68.5 | ) | |||||||||
| Transportation and processing costs deducted from oil and condensate, gas and NGL sales | (15.8 | ) | — | (15.8 | ) | (40.9 | ) | — | (40.9 | ) | |||||||||||||
| Transportation and processing costs, as presented | $ | 28.0 | $ | 60.2 | $ | (32.2 | ) | $ | 93.2 | $ | 202.6 | $ | (109.4 | ) | |||||||||
| (per Boe) | |||||||||||||||||||||||
| Adjusted transportation and processing costs | $ | 3.04 | $ | 4.26 | $ | (1.22 | ) | $ | 3.34 | $ | 4.93 | $ | (1.59 | ) | |||||||||
| Transportation and processing costs deducted from oil and condensate, gas and NGL sales | (1.10 | ) | — | (1.10 | ) | (1.02 | ) | — | (1.02 | ) | |||||||||||||
| Transportation and processing costs, as presented | $ | 1.94 | $ | 4.26 | $ | (2.32 | ) | $ | 2.32 | $ | 4.93 | $ | (2.61 | ) | |||||||||
Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures
This release contains references to the non-GAAP measures of Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures.
The Company defines Discretionary Cash Flow as net cash provided by (used in) operating activities less the changes in operating assets and liabilities. Management believes that this measure is useful to management and investors as a measure of the Company’s ability to internally fund its capital expenditures and to service or incur additional debt.
The Company defines Discretionary Cash Flow in Excess of Capital Expenditures as Discretionary Cash Flow (defined above) less property acquisitions and property, plant equipment, including exploratory well expense. Management believes that this measure is useful to management and investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development.
Below is a reconciliation of Net Cash Provided by (Used in) Operating Activities (a GAAP measure) to Discretionary Cash Flow and Discretionary Cash Flow in Excess of Capital Expenditures. These non-GAAP measures should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP.
| Three Months Ended | Nine Months Ended | ||||||||||||||
| September 30, | September 30, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| (in millions) | |||||||||||||||
| Cash Flow Information: | |||||||||||||||
| Net Cash Provided by (Used in) Operating Activities | $ | 298.0 | $ | 186.8 | $ | 674.9 | $ | 482.8 | |||||||
| Net Cash Provided by (Used in) Investing Activities | (102.3 | ) | 466.0 | (862.9 | ) | (86.2 | ) | ||||||||
| Net Cash Provided by (Used in) Financing Activities | (194.6 | ) | (12.2 | ) | 191.8 | (20.2 | ) | ||||||||
| Discretionary Cash Flow: | |||||||||||||||
| Net Cash Provided by (Used in) Operating Activities | $ | 298.0 | $ | 186.8 | $ | 674.9 | $ | 482.8 | |||||||
| Changes in operating assets and liabilities | (6.8 | ) | (34.4 | ) | 18.9 | (45.1 | ) | ||||||||
| Discretionary Cash Flow | 291.2 | 152.4 | 693.8 | 437.7 | |||||||||||
| Property acquisitions | (3.2 | ) | (17.9 | ) | (48.3 | ) | (94.5 | ) | |||||||
| Property, plant and equipment, including exploratory well expense | (267.8 | ) | (301.7 | ) | (1,032.1 | ) | (779.6 | ) | |||||||
| Discretionary Cash Flow in Excess of Capital Expenditures | $ | 20.2 | $ | (167.2 | ) | $ | (386.6 | ) | $ | (436.4 | ) | ||||
The following tables present QEP’s volumes and average prices for its open derivative positions as of October 31, 2018:
| Production Commodity Derivative Swaps | |||||||||
| Year | Index | Total Volumes | Average Swap Price per Unit |
||||||
| (in millions) | |||||||||
| Oil sales | (bbls) | ($/bbl) | |||||||
| 2018 | NYMEX WTI | 2.7 | $ | 52.45 | |||||
| 2019 | NYMEX WTI | 11.0 | $ | 54.49 | |||||
| 2020 | NYMEX WTI | 2.9 | $ | 62.37 | |||||
| Gas sales | (MMBtu) | ($/MMBtu) | |||||||
| 2018 | NYMEX HH | 8.1 | $ | 3.01 | |||||
| 2019 | NYMEX HH | 43.8 | $ | 2.86 | |||||
| Production Commodity Derivative Basis Swaps | |||||||||||
| Year | Index | Basis | Total Volumes | Weighted-Average Differential |
|||||||
| (in millions) | |||||||||||
| Oil sales | (bbls) | ($/bbl) | |||||||||
| 2018 | NYMEX WTI | Argus WTI Midland | 1.5 | $ | (0.99 | ) | |||||
| 2018 | NYMEX WTI | Argus WTI Houston(1) | 0.1 | $ | 6.30 | ||||||
| 2019 | NYMEX WTI | Argus WTI Midland | 6.6 | $ | (2.22 | ) | |||||
| 2019 | NYMEX WTI | Argus WTI Houston(1) | 0.4 | $ | 4.35 | ||||||
| 2020 | NYMEX WTI | Argus WTI Midland | 1.5 | $ | (1.01 | ) | |||||
| Gas sales | (MMBtu) | ($/MMBtu) | |||||||||
| 2018 | NYMEX HH | IFNPCR | 1.2 | $ | (0.16 | ) | |||||
____________________________
(1) Argus WTI Houston is an index price reflecting the weighted average price of WTI at Magellan’s East Houston crude oil terminal.
