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: October 24, 2017
(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)) |
Section 2 – Financial Information
Item 2.01 | Completion of Acquisition or Disposal of Assets |
As previously reported, on July 26, 2017, QEP Resources, Inc., a Delaware corporation ("QEP" or "the Company"), through its wholly owned subsidiary, QEP Energy Company, a Texas corporation ("Buyer"), entered into a definitive purchase and sale agreement (the "Purchase Agreement") with JM Cox Resources, L.P., a Texas limited partnership ("JM Cox"), Alpine Oil Company, a Texas corporation ("Alpine"), and Kelly Cox ("Cox", and collectively with JM Cox and Alpine, each individually a "Seller" and collectively, "Sellers") to acquire oil and natural gas interests in the Permian Basin, primarily located in Martin County, Texas from Sellers (the "Acquisition"). On October 24, 2017, the Company closed the Acquisition for a purchase price of approximately $683.5 million (the "Purchase Price"), subject to post-closing purchase price adjustments. Approximately 700 additional acres contracted for in the transaction were not included in the closing, but are expected to be acquired by the Company within the next 30 days for an aggregate purchase price not to exceed $38.0 million. Within 10 business days of closing the Acquisition, QEP is obligated to make offers to various persons who own additional oil and gas interests in certain properties included in the Acquisition on substantially the same terms and conditions as the purchase described above. If all offers are accepted, the aggregate purchase price is not expected to exceed $65.0 million.
All of the Purchase Price was funded with proceeds from the sale of assets in Pinedale (the "Pinedale Divestiture"), previously deposited with a qualified intermediary to facilitate a like-kind-exchange under Section 1031 of the Internal Revenue Service Code. The Purchase Price remains subject to certain post-closing adjustments under the terms of the Purchase Agreement.
The Purchase Agreement was filed as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on July 26, 2017, and is incorporated herein by reference. The foregoing description of the Purchase Agreement does not purport to be complete and is qualified in its entirety by the full text of the Purchase Agreement.
This Current Report on Form 8-K 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 Exchange Act. 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. Actual results may differ materially from those predicted as a result of factors over which the Company has no control. Such factors include, but are not limited to, the failure of potential sellers to timely accept the Company’s offers; the inability of the parties to the acquisitions to satisfy the conditions to the consummation of closing; and other factors identified in the Risk Factors section of the Company's Annual Report on Form 10-K for the year ended December 31, 2016, and the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017. The Company undertakes no obligation to publicly correct or update the forward-looking statements to reflect future events or circumstances.
Item 2.02 | Results of Operations and Financial Condition |
On October 25, 2017, the Company issued a press release to report financial and operating results for the period ended September 30, 2017, and to provide an update to 2017 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 September 30, 2017, 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 |
10.1 | Purchase and Sale Agreement, dated July 26, 2017, by and between QEP Energy Company, as buyer, and JM Cox Resources, L.P., Alpine Oil Company, and Kelly Cox, collectively as sellers (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 26, 2017). |
99.1 | Press release issued October 25, 2017, 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) | ||
October 25, 2017 | ||
/s/ Richard J. Doleshek | ||
Richard J. Doleshek | ||
Executive Vice President and Chief Financial Officer | ||
List of Exhibits: | |
Exhibit No. | Exhibit |
10.1 | |
99.1 | |
QEP RESOURCES REPORTS THIRD QUARTER 2017 FINANCIAL AND OPERATING RESULTS
ANNOUNCES CLOSING OF 2017 PERMIAN BASIN ACQUISITION
DENVER — October 25, 2017 — QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported third quarter 2017 financial and operating results.
▪ | Increased net equivalent production in the Permian Basin to a record 25.6 Mboed, a 57% year-over-year increase |
▪ | Increased net equivalent production in the Haynesville/Cotton Valley to 216.6 MMcfed, a 63% year-over-year increase |
▪ | Completed four Williston Basin refracs with a nearly six fold increase in average 30-day incremental oil production |
▪ | Completed the sale of Pinedale Anticline assets for net proceeds of $718.2 million (Pinedale Divestiture) on September 20, 2017 |
▪ | Closed 2017 Permian Basin Acquisition for approximately $683.5 million on October 24, 2017 |
"The closing of the Pinedale Divestiture and our 2017 Permian Basin Acquisition accelerates our transition to become a more crude oil-focused company, expands our inventory of core acreage in the Midland Basin and solidifies our ability to create long-term shareholder value," commented Chuck Stanley, Chairman, President and CEO of QEP. "Moving forward, we are developing our 2018 capital investment program to more closely align with forecasted cash flows while delivering an oil production growth rate in the mid-teens compared with our 2017 guidance. In addition, we continue to evaluate the monetization of non-core assets to further simplify our portfolio and provide additional liquidity to help support future growth."
The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release.
1
QEP Third Quarter 2017 Financial Results
The Company reported a net loss of $3.3 million, or $0.01 per diluted share, for the third quarter 2017 compared with a net loss of $50.9 million, or $0.21 per diluted share, for the third quarter 2016.
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 2017 Adjusted Net Loss (a non-GAAP measure) was $23.9 million, or $0.10 per diluted share, compared with Adjusted Net Loss of $51.1 million, or $0.21 per diluted share, for the third quarter 2016.
Adjusted EBITDA (a non-GAAP measure) for the third quarter 2017 was $193.1 million compared with $169.2 million for the third quarter 2016, a 14% increase, primarily due to an increase in average realized prices and a decrease in transportation and processing costs, partially offset by a decrease in oil equivalent production and an increase in lease operating expense. The definitions and reconciliations of Adjusted Net Income (Loss) and Adjusted EBITDA to net income (loss) are provided within the financial tables at the end of this release.
Production
Oil equivalent production was 14,124.1 Mboe for the third quarter 2017 compared with 14,445.8 Mboe for the third quarter 2016, a 2% decrease. Oil and NGL production were down 4% and 6% respectively, while natural gas production was essentially flat in the third quarter 2017 compared with the third quarter 2016. Third quarter 2017 oil production declined due to a reduction in completion activity and operational issues in the Williston Basin, partially offset by increased production in the Permian Basin. Third quarter 2017 natural gas production was driven primarily by the Company's successful Haynesville Shale well refrac program, while NGL production declined primarily in Pinedale due to reduced completion activity, our midstream provider withholding additional volumes to meet linefill requirements and the Pinedale Divestiture.
Operating Expenses
During the third quarter 2017, lease operating expenses were $5.39 per Boe, transportation and processing costs were $4.26 per Boe and production and property taxes were $2.02 per Boe. General and administrative expenses for the third quarter 2017 were $43.4 million, a decrease of 35% compared with the third quarter 2016, driven primarily by a decrease in legal expenses and loss contingencies, a decrease in share-based compensation and a decrease in bad debt expense.
Capital Investment
Capital investments, excluding acquisitions (on an accrual basis), were $327.3 million for the third quarter 2017 compared with $141.9 million for the third quarter 2016, of which $26.7 million was related to midstream infrastructure in the Permian Basin. QEP also invested $17.9 million to acquire various oil and gas properties, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold acreage in the Permian and Williston basins.
Liquidity
Cash and cash equivalents were $782.6 million at the end of the third quarter 2017, which includes $718.2 million of proceeds from the Pinedale Divestiture deposited with a qualified intermediary to facilitate a like-kind-exchange for the 2017 Permian Basin Acquisition (defined below) assets under Section 1031 of the Internal Revenue Service Code. At the end of the quarter, the Company had no borrowings under its unsecured revolving credit facility.
2
Pinedale Divestiture
On September 20, 2017, QEP closed on its previously announced divestiture of its Pinedale assets for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments. As part of the purchase and sale agreement, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. QEP paid approximately $10.0 million of the $45.0 million deficiency as part of the closing purchase price adjustment.
2017 Permian Basin Acquisition
On October 24, 2017, QEP closed on its previously announced acquisition of oil and gas properties in the Permian Basin for an aggregate purchase price of $683.5 million, subject to customary post-closing adjustments (the 2017 Permian Basin Acquisition). The assets purchased in the 2017 Permian Basin Acquisition consist of approximately 13,000 acres primarily in Martin County, Texas, which are primarily held by production from existing vertical wells. Approximately 700 additional acres contracted for in the transaction were not included in the closing, but are expected to be acquired by the Company within the next 30 days for an aggregate purchase price not to exceed $38.0 million. As noted above, all of the purchase price was funded with proceeds from the Pinedale Divestiture pursuant to a like-kind-exchange transaction under Section 1031 of the Internal Revenue Service Code.
Portfolio Optimization
As part of the Company’s ongoing effort to simplify its portfolio, QEP entered into agreements or closed the sale of several non-core assets, including its Central Basin Platform exploration project in the Permian Basin and other non-core assets in Southwest Wyoming and Utah for total proceeds of approximately $34.5 million during the third quarter. In addition, QEP continues to evaluate the sale of certain upstream and midstream assets as the Company sharpens its focus on the development of its acreage in the core of the Permian Basin.
2017 Guidance
The Company’s guidance assumes no additional 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.
QEP's full year 2017 guidance remains unchanged from September 25, 2017.
Slide 5 in the October 2017 Investor Presentation provides additional details on QEP's 2017 Guidance.
3
2017 Guidance Table | |
2017 | |
Current Forecast | |
Oil production (MMbbl) | 19.5 - 20.0 |
Gas production (Bcf) | 165.0 - 170.0 |
NGL production (MMbbl) | 5.25 - 5.75 |
Total oil equivalent production (MMboe) | 52.3 - 54.1 |
Lease operating and transportation expense (per Boe) | $10.25 - $10.75 |
Depletion, depreciation and amortization (per Boe) | $14.00 - $15.00 |
Production and property taxes (% of field-level revenue) | 8.5% |
(in millions) | |
General and administrative expense(1) | $150 - $160 |
Capital investment (excluding property acquisitions) | |
Drilling, Completion and Equip(2) | $970 - $1,010 |
Infrastructure | $70 - $80 |
Corporate | $10 |
Total capital investment (excluding property acquisitions) | $1,050 - $1,100 |
____________________________
(1) | General and administrative expense includes approximately $25.0 million of non-cash share-based compensation expense. |
(2) | Drilling, Completion and Equip includes approximately $20.0 million of non-operated well completion costs. |
4
2018 Production Outlook
Assuming an oil price of $50.00/Bbl and a natural gas price of $3.00/MMbtu the Company expects 2018 forecasted crude oil production growth to be in the mid-teens compared with the midpoint of the Company's 2017 guidance. The increase in 2018 forecasted crude oil production will be primarily driven by oil production growth in the Permian Basin, partially offset by a decline in Williston Basin oil production.
Operations Summary
Permian Basin
Permian Basin net production averaged approximately 25.6 Mboed (88% liquids) during the third quarter 2017, a 21% increase compared with the second quarter 2017 and a 57% increase compared with the third quarter 2016, a record for the Company in the basin.
QEP completed and turned to sales 10 gross-operated horizontal wells during the quarter (average working interest 100%). The 10 wells targeted two horizons - Middle Spraberry (4) and Spraberry Shale (6). None of the 10 wells completed reached peak production by the end of the quarter. The Middle Spraberry wells were drilled at 10 well/mile density while the Spraberry Shale wells were drilled on a 14 well/mile density.
At the end of the third quarter 2017, the Company had 29 gross-operated horizontal wells waiting on completion (average working interest 100%) targeting the following horizons: Middle Spraberry (7), Lower Spraberry (1), Spraberry Shale (11), Wolfcamp A (4) and Wolfcamp B (6) and 17 gross-operated horizontal wells being drilled (average working interest 99%) and an additional 21 wells for which surface casing has been set but did not have a rig drilling as of September 30, 2017.
The Company also provided an update on the 22 wells turned to sales in the second quarter 2017, 16 on County Line and six on Mustang Springs. The 16 wells completed on County Line targeted three horizons - the Leonard Shale (1), Middle Spraberry (6) and Spraberry Shale (9). The 16 wells had an average peak 24-hour IP of 1,151 Boed (83% oil) and an average IP 30 rate of 935 Boed (81% oil) with an average lateral length of 7,327 feet. The six wells on Mustang Springs targeted two horizons - Wolfcamp A (2) and Wolfcamp B (4). These six wells had an average peak 24-hour IP of 1,238 Boed (88% oil) and an average IP 30 rate of 779 Boed (84% oil) with an average lateral length of 7,087 feet.
Current QEP-operated drilled and completed authorization for expenditure (AFE) well costs for the Permian Basin are detailed on slide 18 of the October 2017 Investor Presentation.
At the end of the third quarter 2017, the Company had six operated rigs in the Permian Basin and an additional rig drilling salt water disposal wells.
Slides 7-11 in the October 2017 Investor Presentation depict QEP's acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net production averaged approximately 46.2 Mboed (86% liquids) during the third quarter 2017, an 8% decrease compared with the second quarter 2017 and a 19% decrease compared with the third quarter 2016.
The Company completed and turned to sales eight gross-operated wells during the third quarter, including six on South Antelope and two on Ft. Berthold (average working interest 85%). Five of the six wells on South Antelope and the two wells completed on Ft. Berthold were in the early stages of flowback at end of the quarter and had not reached peak production by the end of the quarter. The one South Antelope well with sufficient time on production during the quarter had a peak 24-hour IP of 2,494 Boed (77% oil) and an IP 30 rate of 1,194 Boed (77% oil), with a lateral length of 9,986 feet. The Company also participated in six
5
gross non-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 1.5%).
The Company completed four gross-operated refracs on Ft. Berthold (average working interest 93%) during the third quarter with an average per well IP 30 rate uplift of 627 Boed (81% oil). Pre-refrac the four wells averaged 112 Boed (78% oil), while post-refrac the four wells had an average peak 24-hour IP of 1,005 Boed (81% oil) and an average IP 30 of 739 Boed (81% oil).
Current average gross QEP-operated Williston Basin refrac costs are approximately $4.5 million per well. The Company also plans to complete nine additional refracs during the fourth quarter 2017 (five on South Antelope and four on Ft. Berthold).
At the end of the third quarter 2017, QEP had one gross operated well waiting on completion on South Antelope (average working interest 90%) and one well being drilled on Ft. Berthold (average working interest 90%).
The Company also provided an update on the five wells on South Antelope that were in the early stages of flowback at the end of the second quarter 2017. These wells had an average IP 30 rate of 1,123 Boed (74% oil) with an average lateral length of 9,787 feet.
Current QEP-operated drilled and completed AFE well costs for the Williston Basin are detailed on slide 18 of the October 2017 Investor Presentation.
At the end of the third quarter 2017, the Company had one operated rig in the Williston Basin on Ft. Berthold.
Slides 12-14 in the October 2017 Investor Presentation depict QEP's acreage and activity in the Williston Basin.
Haynesville/Cotton Valley
Haynesville/Cotton Valley net production averaged approximately 216.6 MMcfed (36.1 Mboed) (0% liquids) during the third quarter 2017, an 18% increase compared with the second quarter 2017 and a 63% increase compared with the third quarter 2016. The increases were due to the continued success of the ongoing refrac program. During the quarter, the Company completed nine QEP-operated refracs, with an average incremental 24-hour rate increase of 15.3 MMcfed (average working interest 94%).
Current average gross QEP-operated Haynesville refrac costs are approximately $4.9 million per well. The Company expects to refrac approximately 29 wells during 2017.
At the end of the third quarter, the Company had one operated rig in Haynesville/Cotton Valley.
Slides 15-16 in the October 2017 Investor Presentation depict QEP's acreage and activity in Haynesville/Cotton Valley.
Uinta Basin
Uinta Basin net production averaged approximately 59.0 MMcfed (9.8 Mboed) (23% liquids) during the third quarter 2017, of which 31.7 MMcfed (5.3 Mboed) (10% liquids) was from the Lower Mesaverde play. This represents a 1% decrease compared with the second quarter 2017 and a 25% decrease compared with the third quarter 2016.
At the end of the third quarter, the Company had no drilling rigs in the Uinta Basin.
6
Third Quarter 2017 Results Conference Call
QEP’s management will discuss third quarter 2017 results in a conference call on Thursday, October 26, 2017, beginning at 9:00 a.m. EDT. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website immediately after the call through November 26, 2017, or by dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for international calls, and then entering the conference ID # 13671758. In addition, QEP’s slides for the third quarter 2017, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, can be found on the Company’s website.
About QEP Resources, Inc.
QEP Resources, Inc. (NYSE:QEP) is an independent crude oil and natural gas exploration and production company focused in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). For more information, visit QEP's website at: www.qepres.com.
7
Forward-Looking Statements
This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions. Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include, but are not limited to, statements regarding: forecasted production amounts, lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, share-based compensation expense, production and property taxes, and the amount and allocation of capital investment, and related assumptions for such guidance; sharpening our focus on our Permian Basin assets; aligning 2018 capital investment more closely with 2018 cash flows; providing additional liquidity and funding future growth through the monetization of assets; number of refracs in the Haynesville/Cotton Valley and the Williston Basin; and the usefulness of non-GAAP financial measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: disruptions of QEP's ongoing business, distraction of management and employees, increased expenses and adversely affected results of operations from organizational modifications due to the Pinedale Divestiture and the Acquisition; the inability of the parties to satisfy the conditions to the consummation of such transactions; changes in natural gas, NGL and oil prices; liquidity constraints, including those resulting from the cost or unavailability of financing due to debt and equity capital and credit market conditions, changes in our credit rating, our compliance with loan covenants, the increasing credit pressure on our industry or demands for cash collateral by counterparties to derivative and other contracts; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries; the impact of Brexit; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions, natural resources, and fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal and other proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures; strength of the U.S. dollar; elimination of federal income tax deductions for oil and gas exploration and development; drilling results; shortages of oilfield equipment, services and personnel; the availability of storage and refining capacity; operating risks such as unexpected drilling conditions; transportation constraints; weather conditions; changes in maintenance, service and construction costs; permitting delays; outcome of contingencies such as legal proceedings; inadequate supplies of water and/or lack of water disposal sources; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (the 2016 Annual Report on Form 10-K), and Quarterly Report on Form 10-Q for the quarter ended September 30, 2017. QEP Resources undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
Contact | ||
Investors: | Media: | |
William I. Kent, IRC | Brent Rockwood | |
Director, Investor Relations | Director, Communications | |
303-405-6665 | 303-672-6999 | |
8
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
REVENUES | (in millions, except per share amounts) | ||||||||||||||
Oil sales | $ | 218.0 | $ | 201.6 | $ | 655.7 | $ | 553.1 | |||||||
Gas sales | 130.7 | 123.2 | 399.4 | 287.5 | |||||||||||
NGL sales | 32.2 | 19.8 | 84.0 | 56.2 | |||||||||||
Other revenue | 3.6 | 2.5 | 10.3 | 4.3 | |||||||||||
Purchased oil and gas sales | 5.6 | 35.3 | 44.5 | 76.3 | |||||||||||
Total Revenues | 390.1 | 382.4 | 1,193.9 | 977.4 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Purchased oil and gas expense | 6.9 | 37.1 | 45.4 | 80.8 | |||||||||||
Lease operating expense | 76.2 | 50.7 | 215.4 | 163.3 | |||||||||||
Transportation and processing costs | 60.2 | 75.8 | 202.6 | 218.9 | |||||||||||
Gathering and other expense | 1.7 | 0.9 | 5.0 | 3.8 | |||||||||||
General and administrative | 43.4 | 66.5 | 108.3 | 157.9 | |||||||||||
Production and property taxes | 28.5 | 26.8 | 86.1 | 65.3 | |||||||||||
Depreciation, depletion and amortization | 176.9 | 217.8 | 560.2 | 667.5 | |||||||||||
Exploration expenses | 21.3 | 0.2 | 21.7 | 0.9 | |||||||||||
Impairment | 28.3 | 5.0 | 28.4 | 1,188.2 | |||||||||||
Total Operating Expenses | 443.4 | 480.8 | 1,273.1 | 2,546.6 | |||||||||||
Net gain (loss) from asset sales | 185.4 | 5.3 | 205.2 | 5.0 | |||||||||||
OPERATING INCOME (LOSS) | 132.1 | (93.1 | ) | 126.0 | (1,564.2 | ) | |||||||||
Realized and unrealized gains (losses) on derivative contracts | (104.3 | ) | 44.5 | 163.3 | (85.1 | ) | |||||||||
Interest and other income | 0.1 | 4.6 | 2.5 | 5.6 | |||||||||||
Interest expense | (34.4 | ) | (35.9 | ) | (103.1 | ) | (109.2 | ) | |||||||
INCOME (LOSS) BEFORE INCOME TAXES | (6.5 | ) | (79.9 | ) | 188.7 | (1,752.9 | ) | ||||||||
Income tax (provision) benefit | 3.2 | 29.0 | (69.7 | ) | 641.2 | ||||||||||
NET INCOME (LOSS) | $ | (3.3 | ) | $ | (50.9 | ) | $ | 119.0 | $ | (1,111.7 | ) | ||||
Earnings (loss) per common share | |||||||||||||||
Basic | $ | (0.01 | ) | $ | (0.21 | ) | $ | 0.49 | $ | (5.15 | ) | ||||
Diluted | $ | (0.01 | ) | $ | (0.21 | ) | $ | 0.49 | $ | (5.15 | ) | ||||
Weighted-average common shares outstanding | |||||||||||||||
Used in basic calculation | 240.7 | 239.6 | 240.5 | 215.7 | |||||||||||
Used in diluted calculation | 240.7 | 239.6 | 240.5 | 215.7 | |||||||||||
Dividends per common share | $ | — | $ | — | $ | — | $ | — | |||||||
9
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, 2017 | December 31, 2016 | ||||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 782.6 | $ | 443.8 | |||
Accounts receivable, net | 120.4 | 155.7 | |||||
Income tax receivable | 17.9 | 18.6 | |||||
Fair value of derivative contracts | 3.8 | — | |||||
Hydrocarbon inventories, at lower of average cost or net realizable value | 6.1 | 10.4 | |||||
Prepaid expenses and other | 10.2 | 11.6 | |||||
Total Current Assets | 941.0 | 640.1 | |||||
Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
Proved properties | 11,847.2 | 14,232.5 | |||||
Unproved properties | 703.6 | 871.5 | |||||
Gathering and other | 311.0 | 301.8 | |||||
Materials and supplies | 34.6 | 32.7 | |||||
Total Property, Plant and Equipment | 12,896.4 | 15,438.5 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 6,492.3 | 8,797.7 | |||||
Gathering and other | 111.9 | 101.8 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 6,604.2 | 8,899.5 | |||||
Net Property, Plant and Equipment | 6,292.2 | 6,539.0 | |||||
Fair value of derivative contracts | 1.7 | — | |||||
Other noncurrent assets | 112.5 | 66.3 | |||||
TOTAL ASSETS | $ | 7,347.4 | $ | 7,245.4 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | — | $ | 12.3 | |||
Accounts payable and accrued expenses | 388.6 | 269.7 | |||||
Production and property taxes | 37.4 | 30.1 | |||||
Interest payable | 32.8 | 32.9 | |||||
Fair value of derivative contracts | 13.4 | 169.8 | |||||
Current portion of long-term debt | 134.0 | — | |||||
Total Current Liabilities | 606.2 | 514.8 | |||||
Long-term debt | 1,890.6 | 2,020.9 | |||||
Deferred income taxes | 895.7 | 825.9 | |||||
Asset retirement obligations | 189.3 | 225.8 | |||||
Fair value of derivative contracts | 2.4 | 32.0 | |||||
Other long-term liabilities | 125.7 | 123.3 | |||||
Commitments and contingencies | |||||||
EQUITY | |||||||
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.8 million and 240.7 million shares issued, respectively | 2.4 | 2.4 | |||||
Treasury stock – 1.9 million and 1.1 million shares, respectively | (33.2 | ) | (22.9 | ) | |||
Additional paid-in capital | 1,390.5 | 1,366.6 | |||||
Retained earnings | 2,292.3 | 2,173.3 | |||||
Accumulated other comprehensive income (loss) | (14.5 | ) | (16.7 | ) | |||
Total Common Shareholders' Equity | 3,637.5 | 3,502.7 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 7,347.4 | $ | 7,245.4 | |||
10
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended | |||||||
September 30, | |||||||
2017 | 2016 | ||||||
OPERATING ACTIVITIES | (in millions) | ||||||
Net income (loss) | $ | 119.0 | $ | (1,111.7 | ) | ||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||
Depreciation, depletion and amortization | 560.2 | 667.5 | |||||
Deferred income taxes | 68.5 | (581.1 | ) | ||||
Impairment | 28.4 | 1,188.2 | |||||
Bargain purchase gain from acquisition | 0.4 | (4.4 | ) | ||||
Other non-cash activity | (9.4 | ) | — | ||||
Dry hole exploratory well expense | 21.2 | — | |||||
Share-based compensation | 13.5 | 29.0 | |||||
Amortization of debt issuance costs and discounts | 4.8 | 4.8 | |||||
Net (gain) loss from asset sales | (205.2 | ) | (5.0 | ) | |||
Unrealized (gains) losses on marketable securities | (2.1 | ) | (1.2 | ) | |||
Unrealized (gains) losses on derivative contracts | (161.6 | ) | 218.6 | ||||
Changes in operating assets and liabilities | 44.1 | 128.2 | |||||
Net Cash Provided by (Used in) Operating Activities | 481.8 | 532.9 | |||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | (94.5 | ) | (39.9 | ) | |||
Acquisition deposit held in escrow | (36.6 | ) | (30.0 | ) | |||
Property, plant and equipment, including exploratory well expense | (779.6 | ) | (411.2 | ) | |||
Proceeds from disposition of assets | 787.9 | 28.9 | |||||
Net Cash Provided by (Used in) Investing Activities | (122.8 | ) | (452.2 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | (12.3 | ) | (25.5 | ) | |||
Repayment of senior notes | — | (176.8 | ) | ||||
Long-term debt issuance costs paid | (1.1 | ) | — | ||||
Proceeds from credit facility | 2.0 | — | |||||
Repayments of credit facility | (2.0 | ) | — | ||||
Treasury stock repurchases | (6.8 | ) | (4.1 | ) | |||
Proceeds from issuance of common stock, net | — | 781.6 | |||||
Excess tax (provision) benefit on share-based compensation | — | 0.2 | |||||
Net Cash Provided by (Used in) Financing Activities | (20.2 | ) | 575.4 | ||||
Change in cash and cash equivalents | 338.8 | 656.1 | |||||
Beginning cash and cash equivalents | 443.8 | 376.1 | |||||
Ending cash and cash equivalents | $ | 782.6 | $ | 1,032.2 | |||
11
Production by Region | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||
(in Mboe) | |||||||||||||||||
Northern Region | |||||||||||||||||
Williston Basin | 4,252.3 | 5,256.4 | (19 | )% | 13,660.2 | 15,421.9 | (11 | )% | |||||||||
Pinedale | 3,010.8 | 4,007.8 | (25 | )% | 9,842.4 | 12,005.2 | (18 | )% | |||||||||
Uinta Basin | 905.3 | 1,206.5 | (25 | )% | 2,770.6 | 3,741.1 | (26 | )% | |||||||||
Other Northern | 278.1 | 401.3 | (31 | )% | 945.6 | 1,142.4 | (17 | )% | |||||||||
Total Northern Region | 8,446.5 | 10,872.0 | (22 | )% | 27,218.8 | 32,310.6 | (16 | )% | |||||||||
Southern Region | |||||||||||||||||
Permian Basin | 2,351.3 | 1,505.4 | 56 | % | 5,672.9 | 4,605.3 | 23 | % | |||||||||
Haynesville/Cotton Valley | 3,321.2 | 2,037.1 | 63 | % | 8,160.2 | 5,082.5 | 61 | % | |||||||||
Other Southern | 5.1 | 31.3 | (84 | )% | 23.1 | 106.2 | (78 | )% | |||||||||
Total Southern Region | 5,677.6 | 3,573.8 | 59 | % | 13,856.2 | 9,794.0 | 41 | % | |||||||||
Total production | 14,124.1 | 14,445.8 | (2 | )% | 41,075.0 | 42,104.6 | (2 | )% | |||||||||
Total Production | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||
Oil (Mbbl) | 4,827.1 | 5,025.1 | (4 | )% | 14,380.1 | 15,411.0 | (7 | )% | |||||||||
Gas (Bcf) | 46.7 | 46.8 | — | % | 134.8 | 133.1 | 1 | % | |||||||||
NGL (Mbbl) | 1,516.1 | 1,616.5 | (6 | )% | 4,226.4 | 4,502.8 | (6 | )% | |||||||||
Total production (Mboe) | 14,124.1 | 14,445.8 | (2 | )% | 41,075.0 | 42,104.6 | (2 | )% | |||||||||
Average daily production (Mboe) | 153.5 | 157.0 | (2 | )% | 150.5 | 153.7 | (2 | )% | |||||||||
12
Prices | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||||||
Oil (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 45.16 | $ | 40.12 | $ | 45.60 | $ | 35.89 | |||||||||||||
Commodity derivative impact | 2.51 | 3.81 | 1.50 | 5.18 | |||||||||||||||||
Net realized price | $ | 47.67 | $ | 43.93 | 9 | % | $ | 47.10 | $ | 41.07 | 15 | % | |||||||||
Gas (per Mcf) | |||||||||||||||||||||
Average field-level price | $ | 2.80 | $ | 2.63 | $ | 2.96 | $ | 2.16 | |||||||||||||
Commodity derivative impact | (0.01 | ) | 0.01 | (0.15 | ) | 0.38 | |||||||||||||||
Net realized price | $ | 2.79 | $ | 2.64 | 6 | % | $ | 2.81 | $ | 2.54 | 11 | % | |||||||||
NGL (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 21.28 | $ | 12.26 | $ | 19.89 | $ | 12.49 | |||||||||||||
Commodity derivative impact | — | — | — | — | |||||||||||||||||
Net realized price | $ | 21.28 | $ | 12.26 | 74 | % | $ | 19.89 | $ | 12.49 | 59 | % | |||||||||
Average net equivalent price (per Boe) | |||||||||||||||||||||
Average field-level price | $ | 26.97 | $ | 23.86 | $ | 27.73 | $ | 21.30 | |||||||||||||
Commodity derivative impact | 0.83 | 1.35 | 0.05 | 3.10 | |||||||||||||||||
Net realized price | $ | 27.80 | $ | 25.21 | 10 | % | $ | 27.78 | $ | 24.40 | 14 | % | |||||||||
Operating Expenses | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2017 | 2016 | Change | 2017 | 2016 | Change | ||||||||||||||||
(per Boe) | |||||||||||||||||||||
Lease operating expense | $ | 5.39 | $ | 3.51 | 54 | % | $ | 5.24 | $ | 3.88 | 35 | % | |||||||||
Transportation and processing costs | 4.26 | 5.24 | (19 | )% | 4.93 | 5.20 | (5 | )% | |||||||||||||
Production and property taxes | 2.02 | 1.86 | 9 | % | 2.10 | 1.55 | 35 | % | |||||||||||||
Total production costs | $ | 11.67 | $ | 10.61 | 10 | % | $ | 12.27 | $ | 10.63 | 15 | % | |||||||||
13
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 | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Net income (loss) | $ | (3.3 | ) | $ | (50.9 | ) | $ | 119.0 | $ | (1,111.7 | ) | ||||
Interest expense | 34.4 | 35.9 | 103.1 | 109.2 | |||||||||||
Interest and other (income) expense | (0.1 | ) | (4.6 | ) | (2.5 | ) | (5.6 | ) | |||||||
Income tax provision (benefit) | (3.2 | ) | (29.0 | ) | 69.7 | (641.2 | ) | ||||||||
Depreciation, depletion and amortization | 176.9 | 217.8 | 560.2 | 667.5 | |||||||||||
Unrealized (gains) losses on derivative contracts | 116.0 | (24.9 | ) | (161.6 | ) | 218.6 | |||||||||
Exploration expenses | 21.3 | 0.2 | 21.7 | 0.9 | |||||||||||
Net (gain) loss from asset sales | (185.4 | ) | (5.3 | ) | (205.2 | ) | (5.0 | ) | |||||||
Impairment | 28.3 | 5.0 | 28.4 | 1,188.2 | |||||||||||
Other(1) | 8.2 | 25.0 | 8.2 | 32.7 | |||||||||||
Adjusted EBITDA | $ | 193.1 | $ | 169.2 | $ | 541.0 | $ | 453.6 | |||||||
____________________________
(1) | Reflects legal expenses and loss contingencies incurred during the three and nine months ended September 30, 2017 and 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA. |
14
Adjusted Net Income (Loss)
This release also contains references to the non-GAAP measure of Adjusted Net Income (Loss). Management defines Adjusted Net Income (Loss) as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, asset impairments and certain other items. Management uses Adjusted Net Income (Loss) to evaluate QEP’s financial performance and trends, make operating decisions, and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP’s performance from period to period. QEP’s Adjusted Net Income (Loss) may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure) to Adjusted Net Income (Loss). This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except earnings per share) | |||||||||||||||
Net income (loss) | $ | (3.3 | ) | $ | (50.9 | ) | $ | 119.0 | $ | (1,111.7 | ) | ||||
Adjustments to net income (loss) | |||||||||||||||
Unrealized (gains) losses on derivative contracts | 116.0 | (24.9 | ) | (161.6 | ) | 218.6 | |||||||||
Income taxes on unrealized (gains) losses on derivative contracts(1) | (43.0 | ) | 9.1 | 59.6 | (80.0 | ) | |||||||||
Net (gain) loss from asset sales | (185.4 | ) | (5.3 | ) | (205.2 | ) | (5.0 | ) | |||||||
Income taxes on net (gain) loss from asset sales(1) | 68.8 | 1.9 | 75.7 | 1.8 | |||||||||||
Impairment | 28.3 | 5.0 | 28.4 | 1,188.2 | |||||||||||
Income taxes on impairment(1) | (10.5 | ) | (1.8 | ) | (10.5 | ) | (434.9 | ) | |||||||
Other(2) | 8.2 | 25.0 | 8.2 | 32.7 | |||||||||||
Income taxes on other(1) | (3.0 | ) | (9.2 | ) | (3.0 | ) | (12.0 | ) | |||||||
Total after tax adjustments to net income | (20.6 | ) | (0.2 | ) | (208.4 | ) | 909.4 | ||||||||
Adjusted Net Income (Loss) | $ | (23.9 | ) | $ | (51.1 | ) | $ | (89.4 | ) | $ | (202.3 | ) | |||
Earnings (Loss) per Common Share | |||||||||||||||
Diluted earnings per share | $ | (0.01 | ) | $ | (0.21 | ) | $ | 0.49 | $ | (5.15 | ) | ||||
Diluted after-tax adjustments to net income (loss) per share | (0.09 | ) | — | (0.87 | ) | 4.22 | |||||||||
Diluted Adjusted Net Income per share | $ | (0.10 | ) | $ | (0.21 | ) | $ | (0.38 | ) | $ | (0.93 | ) | |||
Weighted-average common shares outstanding | |||||||||||||||
Diluted | 240.7 | 239.6 | 240.5 | 215.7 | |||||||||||
____________________________
(1) | Income tax impact of adjustments is calculated using QEP’s statutory rate of 37.1% and 36.6% for the three months ended September 30, 2017 and 2016, respectively, and QEP's effective tax rate of 36.9% and 36.6% for the nine months ended September 30, 2017 and 2016, respectively. |
(2) | Reflects legal expenses and loss contingencies incurred during the three and nine months ended September 30, 2017 and 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted Net Income. |
15
The following tables present QEP's volumes and average prices for its open derivative positions as of October 20, 2017:
Production Commodity Derivative Swaps | |||||||||
Year | Index | Total Volumes | Average Swap Price per Unit | ||||||
(in millions) | |||||||||
Oil sales | (bbls) | ($/bbl) | |||||||
2017 | NYMEX WTI | 3.6 | $ | 51.51 | |||||
2018 | NYMEX WTI | 15.7 | $ | 52.37 | |||||
2019 | NYMEX WTI | 4.4 | $ | 50.37 | |||||
Gas sales | (MMBtu) | ($/MMBtu) | |||||||
2017 | NYMEX HH | 16.5 | $ | 2.87 | |||||
2017 | IFNPCR | 4.3 | $ | 2.49 | |||||
2018 | NYMEX HH | 109.5 | $ | 2.99 | |||||
2019 | NYMEX HH | 25.6 | $ | 2.87 | |||||
Production Commodity Derivative Basis Swaps | |||||||||||
Year | Index Less Differential | Index | Total Volumes | Weighted-Average Differential | |||||||
(in millions) | |||||||||||
Oil sales | (bbls) | ($/bbl) | |||||||||
2017 | NYMEX WTI | Argus WTI Midland | 1.1 | $ | (0.67 | ) | |||||
2018 (Full Year) | NYMEX WTI | Argus WTI Midland | 7.3 | $ | (1.06 | ) | |||||
2018 (July through December) | NYMEX WTI | Argus WTI Midland | 0.7 | $ | (0.75 | ) | |||||
2019 | NYMEX WTI | Argus WTI Midland | 3.3 | $ | (0.90 | ) | |||||
Gas sales | (MMBtu) | ($/MMBtu) | |||||||||
2018 | NYMEX HH | IFNPCR | 7.3 | $ | (0.16 | ) | |||||
Storage Commodity Derivative Gas Swaps | |||||||||||
Year | Type of Contract | Index | Total Volumes | Average Swap Price per Unit | |||||||
(in millions) | |||||||||||
Gas sales | (MMBtu) | ($/MMBtu) | |||||||||
2017 | SWAP | IFNPCR | 1.4 | $ | 2.89 | ||||||
2018 | SWAP | IFNPCR | 0.5 | $ | 3.09 | ||||||
Gas purchases | (MMBtu) | ($/MMBtu) | |||||||||
2017 | SWAP | IFNPCR | 0.8 | $ | 2.73 | ||||||
16