- 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 well results from our drilling and refracs programs on South Antelope - Increased quarterly production in
Haynesville/Cotton Valley to 314 MMcfed, a 71% year-over-year increase, driven by strong well 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 theWilliston Basin
"Our record
"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
"We continue to make progress on our Strategic Initiatives. In early July, we announced the execution of a definitive agreement to sell our
"While our transition to a pure play
The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release.
QEP Second Quarter 2018 Financial Results
The Company reported a net loss of
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
Adjusted EBITDA (a non-GAAP measure) for the second quarter 2018 was
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
Operating Expenses
During the second quarter 2018, LOE was
During the second quarter 2018, LOE was
Adjusted transportation and processing (T&P) costs (a non-GAAP measure) were
During the second quarter 2018, Adjusted T&P costs were
General and administrative expense was
During the second quarter 2018, production and property taxes were
Production and property taxes were
Capital Investment
Capital investment, excluding property acquisitions, was
During the second quarter 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the
2018 Share Repurchase Program
During the second quarter 2018, the Company settled and retired 592,310 shares that were repurchased in late
Asset Divestitures
On
QEP closed on the sale of several non-core assets during the second quarter 2018 for total proceeds of approximately
During the second quarter 2018, the Company received bids for its
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.
Liquidity
As of June 30, 2018, QEP had
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
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 inmid-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 andHaynesville/Cotton Valley , all of which have been completed in the first half of 2018
Slide 4 in the
| 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
(3) Approximately 70% of the planned capital investment in Drilling, Completion and Equip is focused on projects in the
| 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.
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
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
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
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
At the end of the second quarter 2018, the Company had five operated rigs in the
Slides 7-12 in the
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).
Current QEP-operated drilled and completed AFE well costs for the
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
At the end of the second quarter 2018, the Company had no drilling rigs in the
Slides 13-15 in the
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
At the end of the second quarter, the Company had no drilling rigs in
Slides 16-17 in the
At the end of the second quarter, the Company had no drilling rigs in the
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
About
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
| Contact |
| Investors/Media: |
| William I. Kent, IRC |
| Director, Investor Relations |
| 303-405-6665 |
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 | $ | — | $ | — | $ | — | $ | — | |||||||
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 | |||
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 | |||
| 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 | % | |||||||||
| 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.
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 | |||||||
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.
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 | ) | |||||||||
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 | ) | |||||
____________________________
(1) Argus WTI Houston is an index price reflecting the weighted average price of WTI at Magellan's
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 | ) | |||||