UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
_______________________________________
Date of Report: July 25, 2018
(Date of earliest event reported)
QEP RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Delaware | 001-34778 | 87-0287750 |
(State or other jurisdiction of incorporation) | (Commission File Number) | (I.R.S. Employer Identification No.) |
1050 17th Street, Suite 800
Denver, Colorado 80265
(Address of principal executive offices and zip code)
(303) 672-6900
(Registrant's telephone number, including area code)
Not Applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
□ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
□ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
□ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
□ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Indicate by checkmark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter) | □ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. | □ |
Section 2 – Financial Information
Item 2.02 | Results of Operations and Financial Condition |
On July 25, 2018, the Company issued a press release to report financial and operating results for the period ended June 30, 2018, and to provide an update to 2018 guidance. A copy of the Company's release is attached hereto as Exhibit 99.1, and the information contained therein is incorporated herein by reference.
The Company's press release announcing its financial results for the period ended June 30, 2018, includes non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company's financial and operating performance that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP. Pursuant to the requirements of Regulation G and Item 10(e)(1)(i) of Regulation S-K, the Company has provided quantitative reconciliations within the press release of the non-GAAP financial measures to the most directly comparable GAAP financial measures (unless there is no directly comparable GAAP financial measure).
The information contained in Item 2.02 to this Form 8-K, including the exhibit, shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and the information shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing.
Section 9 – Financial Statements and Exhibits
Item 9.01 | Financial Statements and Exhibits |
(d) Exhibits.
Exhibit No. | Exhibit |
99.1 | Press release issued July 25, 2018, by QEP Resources, Inc. |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
QEP Resources, Inc. | ||
(Registrant) | ||
July 25, 2018 | ||
/s/ Richard J. Doleshek | ||
Richard J. Doleshek | ||
Executive Vice President and Chief Financial Officer | ||
List of Exhibits: | |
Exhibit No. | Exhibit |
99.1 | |
QEP RESOURCES REPORTS SECOND QUARTER 2018 FINANCIAL AND OPERATING RESULTS
AND PROVIDES UPDATE ON ITS STRATEGIC AND FINANCIAL INTIATIVES
DENVER — July 25, 2018 — QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported second quarter 2018 financial and operating results and provided an update on its strategic and financial initiatives (Strategic Initiatives) announced in February.
▪ | Delivered record quarterly oil and condensate production of 6.6 MMbbls, including a record 3.2 MMbbls in the Permian Basin, a 32% and 49% quarter-over-quarter increase, respectively |
▪ | Delivered 20% quarter-over-quarter increase in Williston Basin production driven by strong results from our drilling and refrac programs on South Antelope |
▪ | Increased quarterly production in Haynesville/Cotton Valley to 314 MMcfed, a 71% year-over-year increase, driven by strong results from our drilling and refrac programs |
▪ | Decreased Permian Basin lease operating expense (LOE) to $5.10 per Boe, a 24% 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 |
"Our record Permian Basin oil production performance in the second quarter demonstrates the quality of our assets and underscores the continued success of our 'tank-style' completions," commented Chuck Stanley, Chairman, President and CEO of QEP. "We continue to put more wells on production than originally forecast in the Permian Basin due to operational efficiencies, such as faster drill times and a 33% quarter-over-quarter increase in the number of frac stages completed per crew per month. These efficiency gains have enabled us to drive down gross completed well costs by over five percent since the fourth quarter 2017, while bringing a similar number of wells in the basin onto production, operating fewer drilling rigs and utilizing fewer frac crews than originally planned for the year."
"For the remainder of 2018 we will continue to focus on balancing capital investments with cash flow and will be allocating the vast majority of capital to the Permian Basin. We expect to put approximately 31 wells on production in the Permian Basin in the second half of 2018, with more than 50% of these wells having lateral lengths of 9,000 feet or greater. We expect the addition of these long laterals, along with our current drilling rig and frac crew level, to support our production profile in 2018 and lay the foundation for oil production growth in the Permian Basin in 2019."
"We continue to make progress on our Strategic Initiatives. In early July, we announced the execution of a definitive agreement to sell our Uinta Basin assets for a purchase price of $155 million (Uinta Basin Divestiture), with an anticipated closing in September. During the second quarter, we received bids for our Williston Basin assets, which we believe did not reflect the value of the underlying quality and economics of the assets. Our decision not to accept the current bids for our Williston Basin assets is reflective of our duty to maximize the value of our company and its assets for all of our shareholders. We continue to engage in discussions with several potential buyers regarding the sale of all, or a portion of, our Williston Basin assets."
"While our transition to a pure play Permian Basin company may take longer than we originally anticipated, QEP’s Board and management remain committed to the Strategic Initiatives," concluded Stanley.
The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release.
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QEP Second Quarter 2018 Financial Results
The Company reported a net loss of $336.0 million, or $1.42 per diluted share, for the second quarter 2018 compared with net income of $45.4 million, or $0.19 per diluted share, for the second quarter 2017. The net loss in the second quarter 2018 includes $403.7 million of impairment expense primarily related to the announced sale of the Uinta Basin assets.
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 2018 Adjusted Net Income (a non-GAAP measure) was $13.8 million, or $0.06 per diluted share, compared with an Adjusted Net Loss of $30.2 million, or $0.12 per diluted share, for the second quarter 2017.
Adjusted EBITDA (a non-GAAP measure) for the second quarter 2018 was $282.6 million compared with $177.2 million for the second 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 increased gas production in Haynesville/Cotton Valley. These changes were partially offset by an increase in realized derivative losses, a decrease in gas sales primarily due to the Pinedale divestiture, which occurred in the third quarter 2017 (Pinedale Divestiture) and a reduction 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 14.1 MMboe for the second quarter 2018 compared with 13.9 MMboe for the second quarter 2017, a 2% increase. Oil and condensate production increased 35%, while natural gas and NGL production decreased 16% and 15%, respectively. Second quarter 2018 equivalent production was positively impacted by increased drilling and completion activity in the Permian and Williston basins and Haynesville/Cotton Valley. These increases were partially offset by the loss of 3.3 MMboe of production in Pinedale as a result of the Pinedale Divestiture.
Operating Expenses
During the second quarter 2018, LOE was $66.5 million, a decrease of 5% compared with the second quarter 2017. The decrease in total LOE was primarily due to the Pinedale Divestiture, partially offset by an increase 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 maintenance and repairs, power and fuel and chemical expense.
During the second quarter 2018, LOE was $4.71 per Boe, a decrease of 7% compared with the second quarter 2017. The decrease in LOE per Boe was primarily due to lower cost production from the recent horizontal well completions in the Permian Basin and Haynesville/Cotton Valley partially offset by the loss of lower LOE per Boe production due to the Pinedale Divestiture.
Adjusted transportation and processing (T&P) costs (a non-GAAP measure) were $43.6 million during the second quarter 2018, a decrease of 40% compared with the second quarter 2017, primarily due to the Pinedale Divestiture.
During the second quarter 2018, Adjusted T&P costs were $3.09 per Boe, a decrease of 41% compared with the second quarter 2017, primarily due to the Pinedale Divestiture, which had higher T&P costs per Boe. Excluding the Pinedale Divestiture, Adjusted T&P costs per Boe were down 28% due to decreases in both Haynesville/Cotton Valley and Permian Basin. The Adjusted T&P cost per Boe decreased in Haynesville/Cotton Valley due to increased production, which increased utilization of the Company's firm transportation commitments on interstate pipelines. The decrease in T&P costs per Boe in the Permian Basin was driven by increased production and associated throughput under lower cost T&P contracts. The definition and reconciliation of Adjusted T&P costs to the T&P costs presented in QEP's Condensed Consolidated Statements of Operations are provided within Non-GAAP Measures at the end of this release.
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General and administrative expense was $55.8 million, or $3.95 per Boe, during the second quarter 2018, an increase of 78% compared with the second quarter 2017. The increase in the second quarter 2018 was primarily due to an increase in restructuring costs associated with the implementation of our Strategic Initiatives. In addition to these restructuring costs, QEP recognized an increase in share-based compensation and changes in the mark-to-market value of the Deferred Compensation Wrap Plan and an increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture.
During the second quarter 2018, production and property taxes were $37.6 million, an increase of 32% compared with the second quarter 2017. The increase in production and property taxes was primarily due to increased oil pricing and increased oil and condensate production in the Williston and Permian basins and increased gas production in Haynesville/Cotton Valley, partially offset by the loss of production resulting from the Pinedale Divestiture.
Production and property taxes were $2.66 per Boe, during the second quarter 2018, an increase of 29% compared with the second quarter 2017, but an increase of 63% excluding the Pinedale Divestiture. The 63% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins offset by lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe.
Capital Investment
Capital investment, excluding property acquisitions, was $365.7 million (on an accrual basis) for the second quarter 2018, compared with $306.0 million for the second quarter 2017. Approximately $337.8 million of the capital expenditures was related to the drilling, completion and equipping of wells and $27.9 million was related to infrastructure investment. The increase in capital expenditures was primarily related to increased drilling and completion activity in the Permian and Williston basins and Haynesville/Cotton Valley.
During the second 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 $8.8 million.
2018 Share Repurchase Program
During the second quarter 2018, the Company settled and retired 592,310 shares that were repurchased in late March 2018 at a weighted average price of $9.37 per share, for $5.6 million.
Asset Divestitures
On July 5, 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement to sell natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for cash proceeds of $155.0 million, subject to customary purchase price adjustments. The agreement also includes the assumption of certain contractual obligations associated with gathering and processing contracts. The transaction is expected to close in September 2018.
QEP closed on the sale of several non-core assets during the second quarter 2018 for total proceeds of approximately $15.5 million.
During the second quarter 2018, the Company received bids for its Williston Basin assets. The Company believes that the initial bids received were below values reflective of the underlying quality and economics of the assets. The Company continues to engage in discussions with several potential buyers regarding the sale of all, or a portion of, the Williston Basin assets.
Additionally, in response to unsolicited inquiries, the Company has entered into confidentiality agreements and is providing data to several third parties interested in a transaction involving the Company's Haynesville assets.
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Liquidity
As of June 30, 2018, QEP had $575.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under its revolving credit facility. The Company estimates that, as of June 30, 2018, it could incur additional indebtedness of approximately $675.0 million and be in compliance with the covenants contained in its revolving credit facility.
4
Updated 2018 Guidance
The Company’s updated guidance includes no adjustment for 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, except in the Permian Basin where processing economics support ethane recovery.
QEP's updated full year 2018 guidance is detailed below.
Rig Count
▪ | Permian Basin - average of four and one-half rigs (dropped to four rigs in mid-July 2018 and for balance of year) |
▪ | Williston Basin - average of one-quarter rig (rig released during second quarter 2018) |
▪ | Haynesville/Cotton Valley - average of one-half rig (rig released during second quarter 2018) |
Wells Put on Production:
▪ | Company: approximately 114 net operated wells |
▪ | Permian Basin: approximately 98 net operated wells |
Refracs:
▪ | 27 net refracs in the Williston Basin and Haynesville/Cotton Valley, all of which have been completed in the first half of 2018 |
Slide 4 in the July 2018 Investor Presentation provides additional details on QEP's 2018 Guidance.
2018 Guidance | ||
2018 | 2018 | |
Previous Guidance | Current Guidance | |
Oil & condensate production (MMbbl) | 21.5 - 23.0 | 23.0 - 24.0 |
Gas production (Bcf) | 135.0 - 145.0 | 137.0 - 143.0 |
NGL production (MMbbl) | 4.25 - 4.75 | 4.0 - 4.5 |
Total oil equivalent production (MMboe) | 48.3 - 51.9 | 49.8 - 52.3 |
Adjusted lease operating and transportation expense (per Boe)(1) | $9.00 - $10.00 | $8.50 - $9.50 |
Depletion, depreciation and amortization (per Boe) | $17.00 - $18.00 | $17.00 - $18.00 |
Production and property taxes (% of field-level revenue) | 8.5% | 8.5% |
(in millions) | ||
General and administrative expense(2) | $195 - $215 | $205 - $225 |
Capital investment (excluding property acquisitions) | ||
Drilling, Completion and Equip(3) | $1,000 - $1,100 | $1,000 - $1,100 |
Infrastructure | $60 | $60 |
Corporate | $10 | $10 |
Total capital investment (excluding property acquisitions) | $1,070 - $1,170 | $1,070 - $1,170 |
____________________________
(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 $30.0 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. Includes approximately $20.0 million of non-operated well costs. |
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Updated 2018 Quarterly Production Guidance | ||||||||
1Q 2018 | 2Q 2018 | 2Q 2018 | 3Q 2018 | 4Q 2018 | 2018 | |||
QEP Resources | Actuals | Actuals | Guidance | Current Guidance | ||||
Oil & condensate production (MMbbl) | 5.0 | 6.6 | 5.4 - 5.7 | 6.0 - 6.4 | 5.5 - 6.0 | 23.0 - 24.0 | ||
Gas production (Bcf) | 35.1 | 38.3 | 35.2 - 37.3 | 34.9 - 37.5 | 28.2 - 32.1 | 137.0 - 143.0 | ||
NGL production (MMbbl) | 0.9 | 1.2 | 1.1 - 1.2 | 1.1 - 1.2 | 0.9 - 1.3 | 4.0 - 4.5 | ||
Total oil equivalent production (MMboe) | 11.7 | 14.1 | 12.4 - 13.1 | 12.9 - 13.9 | 11.1 - 12.6 | 49.8 - 52.3 | ||
Total wells put on production (net) | 35.0 | 47.2 | 45 | 18 | 14 | 114 | ||
Total refracs put on production (net) | 14.0 | 12.8 | 10 | — | — | 27 | ||
Permian Basin | ||||||||
Oil & condensate production (MMbbl) | 2.2 | 3.2 | 2.7 - 2.8 | 3.0 - 3.3 | 3.1 - 3.4 | 11.5 - 12.1 | ||
Gas production (Bcf) | 1.9 | 2.1 | 1.9 - 2.1 | 2.4 - 2.6 | 2.4 - 2.6 | 8.8 - 9.2 | ||
NGL production (MMbbl) | 0.3 | 0.4 | 0.35 - 0.40 | 0.40 - 0.45 | 0.35 - 0.40 | 1.44 - 1.54 | ||
Permian Basin equivalent production (MMboe) | 2.8 | 4.0 | 3.4 - 3.6 | 3.8 - 4.2 | 3.9 - 4.2 | 14.4 -15.1 | ||
Permian Basin wells put on production (net) | 31.0 | 36.1 | 33 | 17 | 14 | 98 | ||
Operations Summary
Permian Basin | Williston Basin | Haynesville/Cotton Valley | Uinta Basin | ||||||||||||||||||||
As of June 30, 2018 | |||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
Well Progress | |||||||||||||||||||||||
Drilling | 25 | 24.8 | — | — | — | — | — | — | |||||||||||||||
At total depth - under drilling rig | 2 | 2.0 | — | — | — | — | — | — | |||||||||||||||
Waiting to be completed | 12 | 11.7 | — | — | — | — | — | — | |||||||||||||||
Undergoing completion | 5 | 4.8 | — | — | — | — | — | — | |||||||||||||||
Completed, awaiting production | 8 | 8.0 | — | — | 1 | 1.0 | — | — | |||||||||||||||
Waiting on completion | 27 | 26.5 | — | — | 1 | 1.0 | — | — | |||||||||||||||
Put on production(1) | 37 | 36.1 | 11 | 10.1 | 1 | 1.0 | — | — | |||||||||||||||
____________________________
(1) | Total wells put on production during the three months ended June 30, 2018. |
Permian Basin
Permian Basin net oil equivalent production averaged a record of approximately 44.1 Mboed (91% liquids) during the second quarter 2018, a 43% increase compared with the first quarter 2018 and a 108% increase compared with the second quarter 2017.
In the second quarter 2018, the Company put on production 37 gross-operated horizontal wells (eight on County Line and 29 on Mustang Springs), four more than originally forecast for the second quarter 2018 (average working interest 98%). The greater than planned delivery of wells in the second quarter 2018 was a result of a continued increase in drilling and completion efficiency. Since entering the Permian Basin in 2014, the Company has achieved an almost four-fold increase in the number of frac stages completed per crew per month, with the two crews working for QEP during the second quarter 2018 pumping an average of 442 stages per active crew month.
6
At the end of the second quarter 2018, five of the eight wells on County Line put on production during the quarter had cleaned up and reached average peak 24-hour IP of 164 Boed per 1,000 lateral feet (84% oil) from an average lateral length of 7,247 feet.
At Mustang Springs, the 29 wells were in four one-half-mile wide drilling spacing units (DSUs), one with a 14 well density, two with an 11 well density and one with a ten well density. At the end of the second quarter 2018, six of the 29 wells on Mustang Springs put on production during the quarter had cleaned up and achieved average peak 24-hour IP of 152 Boed per 1,000 feet (84% oil) from an average lateral length of 7,405 feet.
The Company also provided an update on performance of its high-density pilot consisting of 22 wells in a one-half mile wide DSU that was in a very early stage of well cleanup at the end of the first quarter 2018. Of these 22 wells, five were drilled in the Middle Spraberry, seven in the Spraberry Shale, one in the Dean, two in the Wolfcamp A and seven in the Wolfcamp B formations. These wells achieved an average peak 24-hour IP of 88 Boed per 1,000 feet (84% oil) and had an average peak IP30 of 75 Boed per 1,000 feet (83% oil). The performance of these wells met Company expectations given the relatively high density (effectively 47 wellbores per mile-wide unit) compared to the surrounding DSU’s and the performance of these wells has been instrumental in informing the Company's understanding of tank-style development and future DSU and target reservoir well density optimization.
During the second quarter 2018 the Company, as part of its risk management strategy, continued to enter into financial derivatives and physical sales agreements for oil production from the Permian Basin. As of the end of quarter approximately 97% of the Company’s 50.0 Mbod of gross field-level Permian 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 95% of its current and projected gross oil volumes for the remainder of 2018 and 2019. The Company also has 6.0 MMbbls in 2018 and 7.5 MMbbls in 2019 of its projected Permian 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 derivatives.
At the end of the second quarter 2018, the Company had 25 gross-operated horizontal wells in process of being drilled (of which 13 had surface casing set, but had no drilling rig present), two horizontal wells at total depth under drilling rigs (average working interest 100%), 12 horizontal wells waiting to be completed (average working interest 98%), five horizontal wells undergoing completion (average working interest 96%), and eight fully completed horizontal wells awaiting first production, which were part of a tank "pressure wall" (average working interest 100%).
Current QEP-operated drilled and completed authorization for expenditure (AFE) well costs for the Permian Basin are detailed on slide 21 of the July 2018 Investor Presentation.
At the end of the second quarter 2018, the Company had five operated rigs in the Permian Basin. The Company released one of its operated rigs during mid-July 2018.
Slides 7-12 in the July 2018 Investor Presentation depict QEP's acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net oil equivalent production averaged approximately 49.0 Mboed (86% liquids) during the second quarter 2018, an 18% increase compared with the first quarter 2018 and a 3% decrease compared with the second quarter 2017.
In the second quarter 2018, the Company put on production 11 gross-operated horizontal wells (average working interest 92%). The wells were completed with an average lateral length of 10,030 feet and had an average peak 24-hour IP of 289 Boed per 1,000 feet (80% oil). Seven of the eleven wells had 30 or more days on production with an average peak IP 30 of 213 Boed per 1,000 feet (77% oil).
7
Current QEP-operated drilled and completed AFE well costs for the Williston Basin are detailed on slide 21 of the July 2018 Investor Presentation.
The Company also completed and returned to production seven gross-operated refracs on South Antelope (average working interest 97%) during the second quarter 2018. Three of the seven refracs had reached peak oil rates by the end of the quarter with an average IP30 gross uplift of 844 Boed (75% oil). Current average gross QEP-operated Williston Basin refrac costs are approximately $4.9 million per well.
At the end of the second quarter 2018, the Company had no drilling rigs in the Williston Basin.
Slides 13-15 in the July 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 313.9 MMcfed (52.3 Mboed) (0% liquids) during the second quarter 2018, a 10% increase compared with the first quarter 2018 and a 70% increase compared with the second quarter 2017.
The Company put on production one gross operated well during the second quarter 2018 (average working interest 100%). The well was still in the process of cleaning up at quarter end. The Company also had one fully completed horizontal well awaiting first production at the end of the quarter (average working interest 100%).
During the quarter the Company completed and returned to production six QEP-operated refracs, four of which were high density tests, with an average incremental 24-hour rate increase of 13.0 MMcfed (average working interest 99%).
Current average gross QEP-operated Haynesville refrac costs are approximately $4.9 million per well.
At the end of the second quarter, the Company had no drilling rigs in Haynesville/Cotton Valley.
Slides 16-17 in the July 2018 Investor Presentation depict QEP's acreage and activity in Haynesville/Cotton Valley.
Uinta Basin
Uinta Basin net production averaged approximately 54.2 MMcfed (9.0 Mboed) (25% liquids) during the second quarter 2018, a 1% increase compared with the first quarter 2018 and a 9% decrease compared with the second quarter 2017.
At the end of the second quarter, the Company had no drilling rigs in the Uinta Basin.
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Second Quarter 2018 Results Conference Call
QEP’s management will discuss second quarter 2018 results in a conference call on Thursday, July 26, 2018, 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 26, 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 # 13681534. In addition, QEP’s slides for the second 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 Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). For more information, visit QEP's website at: www.qepres.com.
9
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: planned Strategic Initiatives; planned asset divestitures and timing of such divestitures; use of proceeds from sale of assets; transitioning to a pure-play Permian Basin company and the timing of such transition; utilization of QEP’s tank-style completion methodology and anticipated benefits from this methodology; balancing capital investments with cash flow; allocating the vast majority of capital to the Permian Basin; anticipated closing date for the sale of the Uinta Basin assets and novation of derivatives entered into in conjunction with the execution of the purchase and sale agreement for such assets; the number and location of drilling rigs to be deployed, wells to be put on production and refracs; number of new wells having lateral lengths of 9,000 feet or greater; quality of initial bids received for QEP’s Williston Basin assets; forecast production amounts and growth and related assumptions; forecast 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; and flow assurance for 95% of QEP’s current and projected oil volumes for the remainder of 2018 and 2019. 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; 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 |
10
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
REVENUES | (in millions, except per share amounts) | ||||||||||||||
Oil and condensate, gas and NGL sales | $ | 520.3 | $ | 373.0 | $ | 930.1 | $ | 758.2 | |||||||
Other revenue | 3.0 | 2.7 | 8.0 | 6.7 | |||||||||||
Purchased oil and gas sales | 9.1 | 8.0 | 23.2 | 38.9 | |||||||||||
Total Revenues | 532.4 | 383.7 | 961.3 | 803.8 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Purchased oil and gas expense | 9.8 | 9.1 | 25.3 | 38.5 | |||||||||||
Lease operating expense | 66.5 | 70.0 | 139.0 | 139.2 | |||||||||||
Transportation and processing costs | 31.2 | 72.2 | 65.2 | 142.4 | |||||||||||
Gathering and other expense | 3.4 | 1.8 | 6.2 | 3.3 | |||||||||||
General and administrative | 55.8 | 31.3 | 115.9 | 64.9 | |||||||||||
Production and property taxes | 37.6 | 28.5 | 66.5 | 57.6 | |||||||||||
Depreciation, depletion and amortization | 242.2 | 191.5 | 438.7 | 383.3 | |||||||||||
Exploration expenses | 0.1 | — | 0.1 | 0.4 | |||||||||||
Impairment | 403.7 | — | 404.4 | 0.1 | |||||||||||
Total Operating Expenses | 850.3 | 404.4 | 1,261.3 | 829.7 | |||||||||||
Net gain (loss) from asset sales, inclusive of restructuring costs | (3.9 | ) | 19.8 | (0.4 | ) | 19.8 | |||||||||
OPERATING INCOME (LOSS) | (321.8 | ) | (0.9 | ) | (300.4 | ) | (6.1 | ) | |||||||
Realized and unrealized gains (losses) on derivative contracts | (79.1 | ) | 106.7 | (132.3 | ) | 267.6 | |||||||||
Interest and other income (expense) | (3.1 | ) | 1.8 | (3.8 | ) | 2.4 | |||||||||
Interest expense | (38.2 | ) | (34.9 | ) | (73.2 | ) | (68.7 | ) | |||||||
INCOME (LOSS) BEFORE INCOME TAXES | (442.2 | ) | 72.7 | (509.7 | ) | 195.2 | |||||||||
Income tax (provision) benefit | 106.2 | (27.3 | ) | 120.1 | (72.9 | ) | |||||||||
NET INCOME (LOSS) | $ | (336.0 | ) | $ | 45.4 | $ | (389.6 | ) | $ | 122.3 | |||||
Earnings (loss) per common share | |||||||||||||||
Basic | $ | (1.42 | ) | $ | 0.19 | $ | (1.63 | ) | $ | 0.51 | |||||
Diluted | $ | (1.42 | ) | $ | 0.19 | $ | (1.63 | ) | $ | 0.51 | |||||
Weighted-average common shares outstanding | |||||||||||||||
Used in basic calculation | 237.0 | 240.5 | 238.9 | 240.4 | |||||||||||
Used in diluted calculation | 237.0 | 240.6 | 238.9 | 240.5 | |||||||||||
Dividends per common share | $ | — | $ | — | $ | — | $ | — | |||||||
11
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, 2018 | December 31, 2017 | ||||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | — | $ | — | |||
Accounts receivable, net | 175.0 | 141.8 | |||||
Income tax receivable | 5.3 | 4.9 | |||||
Fair value of derivative contracts | 23.7 | 3.4 | |||||
Prepaid expenses | 9.8 | 10.1 | |||||
Other current assets | 0.3 | 4.3 | |||||
Total Current Assets | 214.1 | 164.5 | |||||
Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
Proved properties | 12,852.3 | 11,873.6 | |||||
Unproved properties | 1,041.0 | 1,086.4 | |||||
Gathering and other | 359.7 | 318.7 | |||||
Materials and supplies | 32.2 | 32.9 | |||||
Total Property, Plant and Equipment | 14,285.2 | 13,311.6 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 7,267.1 | 6,642.9 | |||||
Gathering and other | 116.2 | 124.3 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 7,383.3 | 6,767.2 | |||||
Net Property, Plant and Equipment | 6,901.9 | 6,544.4 | |||||
Fair value of derivative contracts | 5.4 | 0.1 | |||||
Other noncurrent assets | 56.5 | 53.0 | |||||
Noncurrent assets held for sale | 211.8 | $ | 632.8 | ||||
TOTAL ASSETS | $ | 7,389.7 | $ | 7,394.8 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | 8.5 | $ | 44.0 | |||
Accounts payable and accrued expenses | 388.0 | 363.8 | |||||
Production and property taxes | 36.3 | 31.6 | |||||
Interest payable | 32.7 | 26.0 | |||||
Fair value of derivative contracts | 155.2 | 103.6 | |||||
Asset retirement obligations | 6.0 | 3.5 | |||||
Total Current Liabilities | 626.7 | 572.5 | |||||
Long-term debt | 2,649.4 | 2,160.8 | |||||
Deferred income taxes | 397.7 | 518.0 | |||||
Asset retirement obligations | 154.6 | 159.0 | |||||
Fair value of derivative contracts | 49.3 | 31.8 | |||||
Other long-term liabilities | 97.8 | 102.2 | |||||
Other long-term liabilities held for sale | 52.8 | 52.6 | |||||
Commitments and contingencies | |||||||
EQUITY | |||||||
Common stock – par value $0.01 per share; 500.0 million shares authorized; 239.7 million and 243.0 million shares issued, respectively | 2.4 | 2.4 | |||||
Treasury stock – 2.7 million and 2.0 million shares, respectively | (41.2 | ) | (34.2 | ) | |||
Additional paid-in capital | 1,415.7 | 1,398.2 | |||||
Retained earnings | 1,994.7 | 2,442.6 | |||||
Accumulated other comprehensive income (loss) | (10.2 | ) | (11.1 | ) | |||
Total Common Shareholders' Equity | 3,361.4 | 3,797.9 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 7,389.7 | $ | 7,394.8 | |||
12
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended | |||||||
June 30, | |||||||
2018 | 2017 | ||||||
OPERATING ACTIVITIES | (in millions) | ||||||
Net income (loss) | $ | (389.6 | ) | $ | 122.3 | ||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||
Depreciation, depletion and amortization | 438.7 | 383.3 | |||||
Deferred income taxes (benefit) | (120.5 | ) | 67.2 | ||||
Impairment | 404.4 | 0.1 | |||||
Share-based compensation | 23.4 | 7.7 | |||||
Amortization of debt issuance costs and discounts | 2.6 | 3.1 | |||||
Bargain purchase gain from acquisition | — | 0.4 | |||||
Net (gain) loss from asset sales, inclusive of restructuring costs | 0.4 | (19.8 | ) | ||||
Unrealized (gains) losses on marketable securities | (0.4 | ) | (1.4 | ) | |||
Unrealized (gains) losses on derivative contracts | 43.6 | (277.6 | ) | ||||
Changes in operating assets and liabilities | (25.7 | ) | 10.7 | ||||
Net Cash Provided by (Used in) Operating Activities | 376.9 | 296.0 | |||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | (45.1 | ) | (76.6 | ) | |||
Property, plant and equipment, including exploratory well expense | (764.3 | ) | (477.9 | ) | |||
Proceeds from disposition of assets | 48.8 | 2.3 | |||||
Net Cash Provided by (Used in) Investing Activities | (760.6 | ) | (552.2 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | (35.5 | ) | (0.5 | ) | |||
Long-term debt issuance costs paid | — | (1.1 | ) | ||||
Proceeds from credit facility | 2,029.5 | — | |||||
Repayments of credit facility | (1,543.5 | ) | — | ||||
Common stock repurchased and retired | (58.4 | ) | — | ||||
Treasury stock repurchases | (5.9 | ) | (6.4 | ) | |||
Other capital contributions | 0.2 | — | |||||
Net Cash Provided by (Used in) Financing Activities | 386.4 | (8.0 | ) | ||||
Change in cash, cash equivalents and restricted cash | 2.7 | (264.2 | ) | ||||
Beginning cash, cash equivalents and restricted cash | 23.4 | 465.4 | |||||
Ending cash, cash equivalents and restricted cash | $ | 26.1 | $ | 201.2 | |||
13
Production by Region | |||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||
(in Mboe) | |||||||||||||||||
Northern Region | |||||||||||||||||
Williston Basin | 4,459.7 | 4,573.9 | (2 | )% | 8,189.4 | 9,407.9 | (13 | )% | |||||||||
Pinedale | — | 3,316.7 | (100 | )% | 0.1 | 6,831.6 | (100 | )% | |||||||||
Uinta Basin | 821.7 | 897.0 | (8 | )% | 1,626.2 | 1,865.3 | (13 | )% | |||||||||
Other Northern | 42.8 | 337.1 | (87 | )% | 148.2 | 667.5 | (78 | )% | |||||||||
Total Northern Region | 5,324.2 | 9,124.7 | (42 | )% | 9,963.9 | 18,772.3 | (47 | )% | |||||||||
Southern Region | |||||||||||||||||
Permian Basin | 4,016.2 | 1,932.1 | 108 | % | 6,799.1 | 3,321.6 | 105 | % | |||||||||
Haynesville/Cotton Valley | 4,761.3 | 2,792.3 | 71 | % | 9,051.8 | 4,839.0 | 87 | % | |||||||||
Other Southern | 4.4 | 11.5 | (62 | )% | 15.9 | 18.0 | (12 | )% | |||||||||
Total Southern Region | 8,781.9 | 4,735.9 | 85 | % | 15,866.8 | 8,178.6 | 94 | % | |||||||||
Total production | 14,106.1 | 13,860.6 | 2 | % | 25,830.7 | 26,950.9 | (4 | )% | |||||||||
Total Production | |||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||
Oil and condensate (Mbbl) | 6,567.6 | 4,870.3 | 35 | % | 11,541.6 | 9,553.0 | 21 | % | |||||||||
Gas (Bcf) | 38.3 | 45.8 | (16 | )% | 73.4 | 88.1 | (17 | )% | |||||||||
NGL (Mbbl) | 1,152.8 | 1,354.9 | (15 | )% | 2,057.2 | 2,710.3 | (24 | )% | |||||||||
Total production (Mboe) | 14,106.1 | 13,860.6 | 2 | % | 25,830.7 | 26,950.9 | (4 | )% | |||||||||
Average daily production (Mboe) | 155.0 | 152.3 | 2 | % | 142.7 | 148.9 | (4 | )% | |||||||||
Prices | |||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||
Oil (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 62.21 | $ | 44.35 | $ | 61.45 | $ | 45.82 | |||||||||||||
Commodity derivative impact | (7.91 | ) | 2.37 | (8.34 | ) | 0.99 | |||||||||||||||
Net realized price | $ | 54.30 | $ | 46.72 | 16 | % | $ | 53.11 | $ | 46.81 | 13 | % | |||||||||
Gas (per Mcf) | |||||||||||||||||||||
Average field-level price | $ | 2.55 | $ | 2.93 | $ | 2.72 | $ | 3.05 | |||||||||||||
Commodity derivative impact | 0.17 | (0.11 | ) | 0.10 | (0.22 | ) | |||||||||||||||
Net realized price | $ | 2.72 | $ | 2.82 | (4 | )% | $ | 2.82 | $ | 2.83 | — | % | |||||||||
NGL (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 22.84 | $ | 16.86 | $ | 22.47 | $ | 19.11 | |||||||||||||
Commodity derivative impact | — | — | — | — | |||||||||||||||||
Net realized price | $ | 22.84 | $ | 16.86 | 35 | % | $ | 22.47 | $ | 19.11 | 18 | % | |||||||||
Average net equivalent price (per Boe) | |||||||||||||||||||||
Average field-level price | $ | 37.77 | $ | 26.91 | $ | 36.98 | $ | 28.13 | |||||||||||||
Commodity derivative impact | (3.23 | ) | 0.46 | (3.45 | ) | (0.36 | ) | ||||||||||||||
Net realized price | $ | 34.54 | $ | 27.37 | 26 | % | $ | 33.53 | $ | 27.77 | 21 | % | |||||||||
14
Operating Expenses | |||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Lease operating expense | $ | 66.5 | $ | 70.0 | (5 | )% | $ | 139.0 | $ | 139.2 | — | % | |||||||||
Adjusted transportation and processing costs(1) | 43.6 | 72.2 | (40 | )% | 90.3 | 142.4 | (37 | )% | |||||||||||||
Production and property taxes | 37.6 | 28.5 | 32 | % | 66.5 | 57.6 | 15 | % | |||||||||||||
$ | 147.7 | $ | 170.7 | (13 | )% | $ | 295.8 | $ | 339.2 | (13 | )% | ||||||||||
(per Boe) | |||||||||||||||||||||
Lease operating expense | $ | 4.71 | $ | 5.05 | (7 | )% | $ | 5.38 | $ | 5.17 | 4 | % | |||||||||
Adjusted transportation and processing costs(1) | 3.09 | 5.21 | (41 | )% | 3.49 | 5.28 | (34 | )% | |||||||||||||
Production and property taxes | 2.66 | 2.06 | 29 | % | 2.57 | 2.14 | 20 | % | |||||||||||||
Total production costs | $ | 10.46 | $ | 12.32 | (15 | )% | $ | 11.44 | $ | 12.59 | (9 | )% | |||||||||
____________________________
(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. |
15
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 | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions) | |||||||||||||||
Net income (loss) | $ | (336.0 | ) | $ | 45.4 | $ | (389.6 | ) | $ | 122.3 | |||||
Interest expense | 38.2 | 34.9 | 73.2 | 68.7 | |||||||||||
Interest and other (income) expense | 3.1 | (1.8 | ) | 3.8 | (2.4 | ) | |||||||||
Income tax provision (benefit) | (106.2 | ) | 27.3 | (120.1 | ) | 72.9 | |||||||||
Depreciation, depletion and amortization | 242.2 | 191.5 | 438.7 | 383.3 | |||||||||||
Unrealized (gains) losses on derivative contracts | 33.6 | (100.3 | ) | 43.6 | (277.6 | ) | |||||||||
Exploration expenses | 0.1 | — | 0.1 | 0.4 | |||||||||||
Net (gain) loss from asset sales, inclusive of restructuring costs | 3.9 | (19.8 | ) | 0.4 | (19.8 | ) | |||||||||
Impairment | 403.7 | — | 404.4 | 0.1 | |||||||||||
Adjusted EBITDA | $ | 282.6 | $ | 177.2 | $ | 454.5 | $ | 347.9 | |||||||
16
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 statements prepared in accordance with GAAP.
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions, except earnings per share) | |||||||||||||||
Net income (loss) | $ | (336.0 | ) | $ | 45.4 | $ | (389.6 | ) | $ | 122.3 | |||||
Adjustments to net income (loss) | |||||||||||||||
Unrealized (gains) losses on derivative contracts | 33.6 | (100.3 | ) | 43.6 | (277.6 | ) | |||||||||
Income taxes on unrealized (gains) losses on derivative contracts(1) | (7.0 | ) | 37.2 | (10.3 | ) | 103.5 | |||||||||
Net (gain) loss from asset sales, inclusive of restructuring costs | 3.9 | (19.8 | ) | 0.4 | (19.8 | ) | |||||||||
Income taxes on net (gain) loss from asset sales, inclusive of restructuring costs(1) | (0.8 | ) | 7.3 | (0.1 | ) | 7.4 | |||||||||
Impairment | 403.7 | — | 404.4 | 0.1 | |||||||||||
Income taxes on impairment(1) | (83.6 | ) | — | (95.4 | ) | — | |||||||||
Total after tax adjustments to net income | 349.8 | (75.6 | ) | 342.6 | (186.4 | ) | |||||||||
Adjusted Net Income (Loss) | $ | 13.8 | $ | (30.2 | ) | $ | (47.0 | ) | $ | (64.1 | ) | ||||
Earnings (Loss) per Common Share | |||||||||||||||
Diluted earnings per share | $ | (1.42 | ) | $ | 0.19 | $ | (1.63 | ) | $ | 0.51 | |||||
Diluted after-tax adjustments to net income (loss) per share | 1.48 | (0.31 | ) | 1.43 | (0.78 | ) | |||||||||
Diluted Adjusted Net Income per share | $ | 0.06 | $ | (0.12 | ) | $ | (0.20 | ) | $ | (0.27 | ) | ||||
Weighted-average common shares outstanding | |||||||||||||||
Diluted | 237.0 | 240.6 | 238.9 | 240.5 | |||||||||||
____________________________
(1) | Income tax impact of adjustments is calculated using QEP’s statutory rate of 20.7% and 37.1% for the three months ended June 30, 2018 and 2017, respectively and QEP's effective tax rate of 23.6% and 37.3% for the six months ended June 30, 2018 and 2017, respectively. |
17
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 statements prepared in accordance with GAAP.
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
(in millions) | |||||||||||||||||||||||
Adjusted transportation and processing costs | $ | 43.6 | $ | 72.2 | $ | (28.6 | ) | $ | 90.3 | $ | 142.4 | $ | (52.1 | ) | |||||||||
Transportation and processing costs deducted from oil and condensate, gas and NGL sales | (12.4 | ) | — | (12.4 | ) | (25.1 | ) | — | (25.1 | ) | |||||||||||||
Transportation and processing costs, as presented | $ | 31.2 | $ | 72.2 | $ | (41.0 | ) | $ | 65.2 | $ | 142.4 | $ | (77.2 | ) | |||||||||
(per Boe) | |||||||||||||||||||||||
Adjusted transportation and processing costs | $ | 3.09 | $ | 5.21 | $ | (2.12 | ) | $ | 3.49 | $ | 5.28 | $ | (1.79 | ) | |||||||||
Transportation and processing costs deducted from oil and condensate, gas and NGL sales | (0.88 | ) | — | (0.88 | ) | (0.97 | ) | — | (0.97 | ) | |||||||||||||
Transportation and processing costs, as presented | $ | 2.21 | $ | 5.21 | $ | (3.00 | ) | $ | 2.52 | $ | 5.28 | $ | (2.76 | ) | |||||||||
18
The following tables present QEP's volumes and average prices for its open derivative positions as of July 20, 2018:
Production Commodity Derivative Swaps | |||||||||
Year | Index | Total Volumes | Average Swap Price per Unit | ||||||
(in millions) | |||||||||
Oil sales | (bbls) | ($/bbl) | |||||||
2018 | NYMEX WTI | 8.3 | $ | 52.46 | |||||
2019 | NYMEX WTI | 9.5 | $ | 52.66 | |||||
2020 | NYMEX WTI | 1.8 | $ | 60.77 | |||||
Gas sales | (MMBtu) | ($/MMBtu) | |||||||
2018 | NYMEX HH | 44.1 | $ | 3.00 | |||||
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 | 4.6 | $ | (0.99 | ) | |||||
2018 | NYMEX WTI | Argus WTI Houston(1) | 0.2 | $ | 6.30 | ||||||
2019 | NYMEX WTI | Argus WTI Midland | 4.7 | $ | (0.77 | ) | |||||
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 | 3.1 | $ | (0.16 | ) | |||||
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(1) | Argus WTI Houston is an index price reflecting the weighted average price of WTI at Magellan's East Houston crude oil terminal. |
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In conjunction with the execution of the purchase and sale agreement for the Uinta Basin Divestiture, QEP, at the request of the buyer, entered into the derivative contracts listed below. Upon the closing of the sale in the third quarter of 2018, the derivative contracts will be novated to the buyer. The following tables present QEP's volumes and average prices for the Uinta Basin Divestiture derivative positions as of July 20, 2018.
Uinta Basin Divestiture Commodity Derivative Swaps | |||||||||
Year | Index | Total Volumes | Average Swap Price per Unit | ||||||
(in millions) | |||||||||
Oil sales | (bbls) | ($/bbl) | |||||||
2018 | NYMEX WTI | 0.1 | $ | 68.55 | |||||
2019 | NYMEX WTI | 0.5 | $ | 65.30 | |||||
2020 | NYMEX WTI | 0.6 | $ | 61.20 | |||||
2021 | NYMEX WTI | 0.6 | $ | 58.50 | |||||
2022 | NYMEX WTI | 0.4 | $ | 56.15 | |||||
2023 | NYMEX WTI | 0.2 | $ | 55.00 | |||||
Gas sales | (MMBtu) | ($/MMBtu) | |||||||
2018 | NYMEX HH | 2.9 | $ | 2.86 | |||||
2019 | NYMEX HH | 13.4 | $ | 2.74 | |||||
2020 | NYMEX HH | 20.2 | $ | 2.63 | |||||
2021 | NYMEX HH | 19.3 | $ | 2.59 | |||||
2022 | NYMEX HH | 8.7 | $ | 2.61 | |||||
2023 | NYMEX HH | 5.4 | $ | 2.68 | |||||
Uinta Basin Divestiture Commodity Derivative Basis Swaps | |||||||||||
Year | Index | Basis | Total Volumes | Weighted-Average Differential | |||||||
Gas sales | (MMBtu) | ($/MMBtu) | |||||||||
2018 | NYMEX HH | IFNPCR | 2.9 | $ | (0.63 | ) | |||||
2019 | NYMEX HH | IFNPCR | 13.4 | $ | (0.77 | ) | |||||
2020 | NYMEX HH | IFNPCR | 20.2 | $ | (0.77 | ) | |||||
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