- Delivered record net oil equivalent production in the
Permian Basin of 30.9 Mboed, including record oil production of 24.0 Mbod - Reported net gas equivalent production of 286.0 MMcfed in
Haynesville/Cotton Valley , a 110% year-over-year increase - Increased 2018 production guidance and forecasted capital expenditures to reflect an accelerated well delivery cadence in the
Permian Basin resulting from significant improvements in drilling and completion efficiency - Opened data rooms for the divestiture of the Company’s Williston and Uinta basin assets
- Commenced execution of an authorized
$1.25 billion share repurchase program
"During the first quarter we delivered strong production growth in the
"As we continue to focus on balancing capital investments and cash flow, we have reduced capital allocated to our
"We also made great progress on our strategic and financial initiatives (Strategic Initiatives) announced in February, which will result in QEP becoming a pure-play Permian Basin company. Data rooms for the Williston and Uinta basin assets are open and we expect to have these asset sales completed during the second half of 2018. We also began executing our share repurchase program by opportunistically repurchasing over 6.2 million shares of common stock in March," concluded Stanley.
The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release.
QEP First 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 first quarter 2018 Adjusted Net Loss (a non-GAAP measure) was
Adjusted EBITDA (a non-GAAP measure) for the first 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 11.7 MMboe for the first quarter 2018 compared with 13.1 MMboe for the first quarter 2017, an 11% decrease. Oil and condensate production increased 6%, while natural gas and NGL production decreased 17% and 33%, respectively. First quarter 2018 equivalent production was positively impacted by increased drilling and completion activity in the
Operating Expenses
During the first quarter 2018, lease operating expense (LOE) was
During the first quarter 2018, Adjusted transportation and processing (T&P) costs (a non-GAAP measure) were
During the first quarter 2018, production and property taxes were
During the first quarter 2018, general and administrative expense was
Capital Investment
Capital investment, excluding property acquisitions, was
During the first quarter 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the
Share Repurchase
During
Asset Divestitures
QEP closed on the sale of several non-core assets for total proceeds of approximately
Liquidity
As of March 31, 2018, QEP had
2018 Strategic Initiatives
In
- Divest of the Company’s Williston and Uinta basin assets
- Market remaining non-Permian assets, including the
Haynesville/Cotton Valley , in the second half of 2018 - Use proceeds from asset sales to fund
Permian Basin development program until the program reaches operating cash flow neutrality in 2019, reduce debt and return cash to shareholders through share repurchases - Authorized a
$1.25 billion share repurchase program(1)
____________________________
(1) Subject to available liquidity, market conditions and proceeds from asset sales.
Updated 2018 Guidance
The Company’s updated guidance assumes no additional property acquisitions or divestitures, other than those executed in the first quarter 2018, 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) - expected to drop to four rigs inMay 2018 for balance of yearWilliston Basin (average of one-quarter rig) - rig released onApril 9, 2018 Haynesville/Cotton Valley (average of one-half rig) - rig expected to be releasedmid-May 2018
Wells Put on Production:
- Company: approximately 120 net operated wells
Permian Basin : approximately 104 net operated wells
Refracs:
- Approximately 28 net refracs between the
Williston Basin and Haynesville/Cotton
Slide 7 in the
| 2018 Guidance | |||||||||||
| 2018 | 2018 | ||||||||||
| Previous Forecast | Current Forecast | ||||||||||
| Oil & condensate production (MMbbl) | 21.0 - 22.5 | 21.5 - 23.0 | |||||||||
| Gas production (Bcf) | 132.0 - 143.0 | 135.0 - 145.0 | |||||||||
| NGL production (MMbbl) | 4.7 - 5.2 | 4.25 - 4.75 | |||||||||
| Total oil equivalent production (MMboe) | 47.7 - 51.5 | 48.3 - 51.9 | |||||||||
| Lease operating and transportation expense (per Boe)(1) | $9.00 - $10.00 | $9.00 - $10.00 | |||||||||
| Depletion, depreciation and amortization (per Boe) | $17.50 - $18.50 | $17.00 - $18.00 | |||||||||
| Production and property taxes (% of field-level revenue) | 8.5 | % | 8.5 | % | |||||||
| (in millions) | |||||||||||
| General and administrative expense(2) | $185 - $205 | $195 - $215 | |||||||||
| Capital investment (excluding property acquisitions) | |||||||||||
| Drilling, Completion and Equip(3) | $965 - $1,065 | $1,000 - $1,100 | |||||||||
| Infrastructure | $50 | $60 | |||||||||
| Corporate | $10 | $10 | |||||||||
| Total capital investment (excluding property acquisitions) | $1,025 - $1,125 | $1,070 - $1,170 | |||||||||
| (1) | Lease operating and transportation expense (per Boe) is calculated using adjusted transportation and processing costs, a non-GAAP measure. Refer to Non-GAAP Measures at the end of this release. | ||
| (2) | General and administrative expense includes approximately $25.0 million of non-cash share-based compensation expense and approximately $20.0 million of estimated termination benefits and retention program expense. | ||
| (3) | Approximately 70% of the planned capital investment is focused on projects in the Permian Basin. Drilling, Completion and Equip includes approximately $20.0 million of non-operated well completion costs. | ||
| Updated 2018 Quarterly Production Guidance | ||||||||||||
| 1Q 2018 | 1Q 2018 | 2Q 2018 | 3Q 2018 | 4Q 2018 | 2018 | |||||||
| QEP Resources | Forecast | Actuals | Current Forecast | |||||||||
| Oil & condensate production (MMbbl) | 4.5 - 4.7 | 5.0 | 5.4 - 5.7 | 5.7 - 6.3 | 5.4 - 5.9 | 21.5 - 23.0 | ||||||
| Gas production (Bcf) | 31.7 - 33.6 | 35.1 | 35.2 - 37.3 | 35.6 - 39.0 | 29.1 - 33.6 | 135.0 - 145.0 | ||||||
| NGL production (MMbbl) | 1.0 - 1.1 | 0.9 | 1.1 - 1.2 | 1.2 - 1.3 | 1.1 - 1.3 | 4.25 - 4.75 | ||||||
| Total oil equivalent production (MMboe) | 10.8 - 11.4 | 11.7 | 12.4 - 13.1 | 12.8 - 14.3 | 11.3 - 12.8 | 48.3 - 51.9 | ||||||
| Total wells put on production (net) | 20 | 35 | 45 | 24 | 16 | 120 | ||||||
| Total refracs put on production (net) | 14 | 14 | 10 | 4 | — | 28 | ||||||
| Permian Basin | ||||||||||||
| Oil & condensate production (MMbbl) | 2.0 - 2.1 | 2.2 | 2.7 - 2.8 | 3.0 - 3.3 | 3.1 - 3.4 | 11.0 - 11.7 | ||||||
| Gas production (Bcf) | 1.6 - 1.8 | 1.9 | 1.9 - 2.1 | 2.4 - 2.6 | 2.5 - 2.7 | 8.7 - 9.3 | ||||||
| NGL production (MMbbl) | 0.30 - 0.35 | 0.3 | 0.35 - 0.40 | 0.40 - 0.45 | 0.42 - 0.47 | 1.48 - 1.63 | ||||||
| Permian Basin equivalent production (MMboe) | 2.6 - 2.8 | 2.8 | 3.4 - 3.6 | 3.8 - 4.2 | 3.9 - 4.3 | 13.9 -14.8 | ||||||
| Permian Basin wells put on production (net) | 18 | 31 | 33 | 24 | 16 | 104 | ||||||
Operations Summary
| Permian Basin | Williston Basin | Haynesville/Cotton Valley |
Uinta Basin | |||||||||||||||||||||
| As of March 31, 2018 | ||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||
| Well Progress | ||||||||||||||||||||||||
| Drilling | 20 | 19.6 | 1 | 0.5 | 2 | 2.0 | — | — | ||||||||||||||||
| At total depth - under drilling rig | 8 | 7.7 | 5 | 5.0 | — | — | — | — | ||||||||||||||||
| Waiting to be completed | 15 | 14.4 | 2 | 2.0 | — | — | — | — | ||||||||||||||||
| Undergoing completion | 6 | 6.0 | 2 | 2.0 | — | — | — | — | ||||||||||||||||
| Completed, awaiting production | 9 | 9.0 | 1 | 1.0 | — | — | — | — | ||||||||||||||||
| Waiting on completion | 38 | 37.1 | 10 | 10.0 | — | — | — | — | ||||||||||||||||
| Put on production(1) | 31 | 31.0 | — | — | 2 | 2.0 | 2 | 2.0 | ||||||||||||||||
| (1) | Total wells put on production during the quarter ended March 31, 2018. |
In the first quarter 2018, the Company put on production 31 gross-operated horizontal wells, 13 more than originally forecast, in the first quarter 2018 (average working interest 100%) in two, one-half-mile wide drilling spacing units (DSU), one DSU with nine and the other DSU with 22 wells. While the majority of the wells were still in the process of cleaning up at the end of the quarter, early performance suggests the wells are performing at or above expectations, based on their respective well densities. The greater than planned delivery of wells in the first quarter 2018 was due to decreased drilling times and better than forecast completion efficiency. Since entering the
At the end of the first quarter 2018, the Company had 20 gross-operated horizontal wells in process of being drilled (of which nine had surface casing set, but had no drilling rig present), eight horizontal wells at total depth under drilling rigs (average working interest 96%), 15 horizontal wells waiting to be completed (average working interest 96%), six horizontal wells undergoing completion (average working interest 100%), and nine 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 first quarter 2018, the Company had six operated rigs in the
Slides 9-16 in the
The Company completed and returned to production seven gross-operated refracs on South Antelope (average working interest 97%) during the first quarter 2018. None of the seven refracs had reached peak oil rates by the end of the quarter. The Company also plans to complete eight additional refracs on South Antelope during the remainder of 2018. Current average gross
At the end of the first quarter 2018, the Company had one gross-operated horizontal well being drilled (working interest 50%), five horizontal wells at total depth under drilling rigs (average working interest 100%), two gross-operated horizontal wells waiting to be completed (average working interest 100%), two horizontal wells undergoing completion (average working interest 100%), and one fully completed horizontal well awaiting first production (working interest 100%), all on South Antelope.
Current QEP-operated drilled and completed AFE well costs for the
At the end of the first quarter 2018, the Company had one operated rig in the
Slides 17-19 in the
The Company put on production two gross operated wells during the first quarter 2018 (average working interest 100%). The first well put on production in the quarter had a peak 24-hour IP rate of 44.4 MMcfed (100% gas) with a lateral length of 9,725 feet. The second well put on production in the quarter had a peak 24-hour IP rate of 38.3 MMcfed (100% gas) with a lateral length of 9,947 feet.
During the quarter the Company completed and returned to production seven QEP-operated refracs, with an average incremental 24-hour rate increase of 14.6 MMcfed (average working interest 99%). The Company expects to refrac approximately six additional net operated wells during 2018.
Current average gross QEP-operated Haynesville refrac costs are approximately
At the end of the first quarter, the Company had one operated rig in
Slides 20-21 in the
During the first quarter 2018, the Company put on production two gross operated vertical wells (average working interest 100%).
At the end of the first quarter, the Company had no drilling rigs in the
Slide 22 in the
First Quarter 2018 Results Conference Call
QEP’s management will discuss first quarter 2018 results in a conference call on Thursday, April 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; factors impacting the timing and amount of purchases under QEP’s share repurchase program; becoming a pure-play Permian Basin company; utilization of QEP’s tank-style completion methodology and anticipated benefits from this methodology; reaching operating cash flow neutrality in 2019; the number and location of drilling rigs to be deployed, wells to be put on production and refracs; increased number of wells to be completed; 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, termination benefits and retention program expense, 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; and the amount of additional indebtedness QEP could incur and be compliance with loan covenants. 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; 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, 2017. QEP undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
| Contact |
| Investors/Media: |
| William I. Kent, IRC |
| Director, Investor Relations |
| 303-405-6665 |
| QEP RESOURCES, INC. | |||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||
| (Unaudited) | |||||||
| Three Months Ended | |||||||
| March 31, | |||||||
| 2018 | 2017 | ||||||
| REVENUES | (in millions, except per share amounts) | ||||||
| Oil and condensate, gas and NGL sales | $ | 409.8 | $ | 385.2 | |||
| Other revenue | 5.0 | 4.0 | |||||
| Purchased oil and gas sales | 14.1 | 30.9 | |||||
| Total Revenues | 428.9 | 420.1 | |||||
| OPERATING EXPENSES | |||||||
| Purchased oil and gas expense | 15.5 | 29.4 | |||||
| Lease operating expense | 72.5 | 69.2 | |||||
| Transportation and processing costs | 34.0 | 70.2 | |||||
| Gathering and other expense | 2.8 | 1.5 | |||||
| General and administrative | 60.1 | 33.6 | |||||
| Production and property taxes | 28.9 | 29.1 | |||||
| Depreciation, depletion and amortization | 196.5 | 191.8 | |||||
| Exploration expenses | — | 0.4 | |||||
| Impairment | 0.7 | 0.1 | |||||
| Total Operating Expenses | 411.0 | 425.3 | |||||
| Net gain (loss) from asset sales | 3.5 | — | |||||
| OPERATING INCOME (LOSS) | 21.4 | (5.2 | ) | ||||
| Realized and unrealized gains (losses) on derivative contracts | (53.2 | ) | 160.9 | ||||
| Interest and other income (expense) | (0.7 | ) | 0.6 | ||||
| Interest expense | (35.0 | ) | (33.8 | ) | |||
| INCOME (LOSS) BEFORE INCOME TAXES | (67.5 | ) | 122.5 | ||||
| Income tax (provision) benefit | 13.9 | (45.6 | ) | ||||
| NET INCOME (LOSS) | $ | (53.6 | ) | $ | 76.9 | ||
| Earnings (loss) per common share | |||||||
| Basic | $ | (0.22 | ) | $ | 0.32 | ||
| Diluted | $ | (0.22 | ) | $ | 0.32 | ||
| Weighted-average common shares outstanding | |||||||
| Used in basic calculation | 240.9 | 240.2 | |||||
| Used in diluted calculation | 240.9 | 240.3 | |||||
| Dividends per common share | $ | — | $ | — | |||
| QEP RESOURCES, INC. | |||||||
| CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||
| (Unaudited) | |||||||
| March 31, 2018 |
December 31, 2017 |
||||||
| ASSETS | (in millions) | ||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Accounts receivable, net | 130.2 | 142.1 | |||||
| Income tax receivable | 4.7 | 4.9 | |||||
| Fair value of derivative contracts | 3.2 | 3.4 | |||||
| Hydrocarbon inventories, at lower of average cost or net realizable value | 2.1 | 3.6 | |||||
| Prepaid expenses | 9.4 | 10.7 | |||||
| Other current assets | 0.2 | 0.7 | |||||
| Total Current Assets | 149.8 | 165.4 | |||||
| Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
| Proved properties | 12,676.1 | 12,470.9 | |||||
| Unproved properties | 1,073.7 | 1,095.8 | |||||
| Gathering and other | 383.4 | 319.7 | |||||
| Materials and supplies | 38.4 | 37.8 | |||||
| Total Property, Plant and Equipment | 14,171.6 | 13,924.2 | |||||
| Less Accumulated Depreciation, Depletion and Amortization | |||||||
| Exploration and production | 6,660.8 | 6,642.9 | |||||
| Gathering and other | 130.6 | 124.3 | |||||
| Total Accumulated Depreciation, Depletion and Amortization | 6,791.4 | 6,767.2 | |||||
| Net Property, Plant and Equipment | 7,380.2 | 7,157.0 | |||||
| Fair value of derivative contracts | 4.5 | 0.1 | |||||
| Other noncurrent assets | 74.1 | 72.3 | |||||
| TOTAL ASSETS | $ | 7,608.6 | $ | 7,394.8 | |||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities | |||||||
| Checks outstanding in excess of cash balances | $ | 19.8 | $ | 44.0 | |||
| Accounts payable and accrued expenses | 400.9 | 364.6 | |||||
| Production and property taxes | 31.9 | 31.6 | |||||
| Interest payable | 33.4 | 26.0 | |||||
| Fair value of derivative contracts | 116.9 | 103.6 | |||||
| Asset retirement obligations | 10.1 | 7.5 | |||||
| Total Current Liabilities | 613.0 | 577.3 | |||||
| Long-term debt | 2,458.1 | 2,160.8 | |||||
| Deferred income taxes | 504.0 | 518.0 | |||||
| Asset retirement obligations | 200.4 | 206.6 | |||||
| Fair value of derivative contracts | 32.8 | 31.8 | |||||
| Other long-term liabilities | 103.6 | 102.4 | |||||
| Commitments and contingencies | |||||||
| EQUITY | |||||||
| Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.3 million and 243.0 million shares issued, respectively | 2.4 | 2.4 | |||||
| Treasury stock – 2.6 million and 2.0 million shares, respectively | (39.5 | ) | (34.2 | ) | |||
| Additional paid-in capital | 1,408.0 | 1,398.2 | |||||
| Retained earnings | 2,336.3 | 2,442.6 | |||||
| Accumulated other comprehensive income (loss) | (10.5 | ) | (11.1 | ) | |||
| Total Common Shareholders' Equity | 3,696.7 | 3,797.9 | |||||
| TOTAL LIABILITIES AND EQUITY | $ | 7,608.6 | $ | 7,394.8 | |||
| QEP RESOURCES, INC. | |||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
| (Unaudited) | |||||||
| Three Months Ended | |||||||
| March 31, | |||||||
| 2018 | 2017 | ||||||
| OPERATING ACTIVITIES | (in millions) | ||||||
| Net income (loss) | $ | (53.6 | ) | $ | 76.9 | ||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||
| Depreciation, depletion and amortization | 196.5 | 191.8 | |||||
| Deferred income taxes (benefit) | (14.1 | ) | 45.6 | ||||
| Impairment | 0.7 | 0.1 | |||||
| Share-based compensation | 11.2 | 6.0 | |||||
| Amortization of debt issuance costs and discounts | 1.3 | 1.5 | |||||
| Bargain purchase gain from acquisition | — | 0.4 | |||||
| Net (gain) loss from asset sales | (3.5 | ) | — | ||||
| Unrealized (gains) losses on marketable securities | 0.1 | (0.8 | ) | ||||
| Unrealized (gains) losses on derivative contracts | 10.0 | (177.3 | ) | ||||
| Changes in operating assets and liabilities | 11.8 | 5.7 | |||||
| Net Cash Provided by (Used in) Operating Activities | 160.4 | 149.9 | |||||
| INVESTING ACTIVITIES | |||||||
| Property acquisitions | (36.2 | ) | (68.2 | ) | |||
| Property, plant and equipment, including exploratory well expense | (370.7 | ) | (177.3 | ) | |||
| Proceeds from disposition of assets | 33.3 | 0.2 | |||||
| Net Cash Provided by (Used in) Investing Activities | (373.6 | ) | (245.3 | ) | |||
| FINANCING ACTIVITIES | |||||||
| Checks outstanding in excess of cash balances | (24.2 | ) | (3.1 | ) | |||
| Proceeds from credit facility | 1,068.5 | — | |||||
| Repayments of credit facility | (772.5 | ) | — | ||||
| Common stock repurchased and retired | (52.8 | ) | — | ||||
| Treasury stock repurchases | (4.7 | ) | (6.4 | ) | |||
| Net Cash Provided by (Used in) Financing Activities | 214.3 | (9.5 | ) | ||||
| Change in cash, cash equivalents and restricted cash | 1.1 | (104.9 | ) | ||||
| Beginning cash, cash equivalents and restricted cash | 23.4 | 465.4 | |||||
| Ending cash, cash equivalents and restricted cash | $ | 24.5 | $ | 360.5 | |||
| Production by Region | |||||||||
| Three Months Ended March 31, | |||||||||
| 2018 | 2017 | Change | |||||||
| (in Mboe) | |||||||||
| Northern Region | |||||||||
| Williston Basin | 3,729.7 | 4,834.0 | (23 | )% | |||||
| Pinedale | 0.1 | 3,514.9 | (100 | )% | |||||
| Uinta Basin | 804.5 | 968.3 | (17 | )% | |||||
| Other Northern | 105.4 | 330.4 | (68 | )% | |||||
| Total Northern Region | 4,639.7 | 9,647.6 | (52 | )% | |||||
| Southern Region | |||||||||
| Permian Basin | 2,782.9 | 1,389.5 | 100 | % | |||||
| Haynesville/Cotton Valley | 4,290.5 | 2,046.7 | 110 | % | |||||
| Other Southern | 11.5 | 6.5 | 77 | % | |||||
| Total Southern Region | 7,084.9 | 3,442.7 | 106 | % | |||||
| Total production | 11,724.6 | 13,090.3 | (10 | )% | |||||
| Total Production | |||||||||
| Three Months Ended March 31, | |||||||||
| 2018 | 2017 | Change | |||||||
| Oil (Mbbl) | 4,974.0 | 4,682.7 | 6 | % | |||||
| Gas (Bcf) | 35.1 | 42.3 | (17 | )% | |||||
| NGL (Mbbl) | 904.4 | 1,355.4 | (33 | )% | |||||
| Total production (Mboe) | 11,724.6 | 13,090.3 | (10 | )% | |||||
| Average daily production (Mboe) | 130.3 | 145.4 | (10 | )% | |||||
| Prices | |||||||||||
| Three Months Ended March 31, | |||||||||||
| 2018 | 2017 | Change | |||||||||
| Oil (per bbl) | |||||||||||
| Average field-level price | $ | 60.45 | $ | 47.35 | |||||||
| Commodity derivative impact | (8.91 | ) | (0.43 | ) | |||||||
| Net realized price | $ | 51.54 | $ | 46.92 | 10 | % | |||||
| Gas (per Mcf) | |||||||||||
| Average field-level price | $ | 2.91 | $ | 3.18 | |||||||
| Commodity derivative impact | 0.03 | (0.34 | ) | ||||||||
| Net realized price | $ | 2.94 | $ | 2.84 | 4 | % | |||||
| NGL (per bbl) | |||||||||||
| Average field-level price | $ | 21.99 | $ | 21.36 | |||||||
| Commodity derivative impact | — | — | |||||||||
| Net realized price | $ | 21.99 | $ | 21.36 | 3 | % | |||||
| Average net equivalent price (per Boe) | |||||||||||
| Average field-level price | $ | 36.04 | $ | 29.43 | |||||||
| Commodity derivative impact | (3.70 | ) | (1.24 | ) | |||||||
| Net realized price | $ | 32.34 | $ | 28.19 | 15 | % | |||||
| Operating Expenses | |||||||||||
| Three Months Ended March 31, | |||||||||||
| 2018 | 2017 | Change | |||||||||
| (in millions) | |||||||||||
| Lease operating expense | $ | 72.5 | $ | 69.2 | 5 | % | |||||
| Adjusted transportation and processing costs(1) | 46.7 | 70.2 | (33 | )% | |||||||
| Production and property taxes | 28.9 | 29.1 | (1 | )% | |||||||
| $ | 148.1 | $ | 168.5 | (12 | )% | ||||||
| (per Boe) | |||||||||||
| Lease operating expense | $ | 6.18 | $ | 5.29 | 17 | % | |||||
| Adjusted transportation and processing costs(1) | 3.98 | 5.36 | (26 | )% | |||||||
| Production and property taxes | 2.47 | 2.23 | 11 | % | |||||||
| Total production costs | $ | 12.63 | $ | 12.88 | (2 | )% | |||||
| (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 | ||||||||
| March 31, | ||||||||
| 2018 | 2017 | |||||||
| (in millions) | ||||||||
| Net income (loss) | $ | (53.6 | ) | $ | 76.9 | |||
| Interest expense | 35.0 | 33.8 | ||||||
| Interest and other (income) expense | 0.7 | (0.6 | ) | |||||
| Income tax provision (benefit) | (13.9 | ) | 45.6 | |||||
| Depreciation, depletion and amortization | 196.5 | 191.8 | ||||||
| Unrealized (gains) losses on derivative contracts | 10.0 | (177.3 | ) | |||||
| Exploration expenses | — | 0.4 | ||||||
| Net (gain) loss from asset sales | (3.5 | ) | — | |||||
| Impairment | 0.7 | 0.1 | ||||||
| Adjusted EBITDA | $ | 171.9 | $ | 170.7 | ||||
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 March 31, | ||||||||
| 2018 | 2017 | |||||||
| (in millions, except earnings per share) | ||||||||
| Net income (loss) | $ | (53.6 | ) | $ | 76.9 | |||
| Adjustments to net income (loss) | ||||||||
| Unrealized (gains) losses on derivative contracts | 10.0 | (177.3 | ) | |||||
| Income taxes on unrealized (gains) losses on derivative contracts(1) | (2.1 | ) | 65.8 | |||||
| Net (gain) loss from asset sales | (3.5 | ) | — | |||||
| Income taxes on net (gain) loss from asset sales(1) | 0.7 | — | ||||||
| Impairment | 0.7 | 0.1 | ||||||
| Income taxes on impairment(1) | (0.1 | ) | — | |||||
| Total after tax adjustments to net income | 5.7 | (111.4 | ) | |||||
| Adjusted Net Income (Loss) | $ | (47.9 | ) | $ | (34.5 | ) | ||
| Earnings (Loss) per Common Share | ||||||||
| Diluted earnings per share | $ | (0.22 | ) | $ | 0.32 | |||
| Diluted after-tax adjustments to net income (loss) per share | 0.02 | (0.46 | ) | |||||
| Diluted Adjusted Net Income per share | $ | (0.20 | ) | $ | (0.14 | ) | ||
| Weighted-average common shares outstanding | ||||||||
| Diluted | 240.9 | 240.3 | ||||||
| (1) | Income tax impact of adjustments is calculated using QEP’s statutory rate of 20.7% and 37.1% for the three months ended March 31, 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 March 31, | ||||||||||||
| 2018 | 2017 | Change | ||||||||||
| (in millions) | ||||||||||||
| Adjusted transportation and processing costs | $ | 46.7 | $ | 70.2 | $ | (23.5 | ) | |||||
| Transportation and processing costs deducted from oil and condensate, gas and NGL sales | (12.7 | ) | — | (12.7 | ) | |||||||
| Transportation and processing costs, as presented | $ | 34.0 | $ | 70.2 | $ | (36.2 | ) | |||||
| (per Boe) | ||||||||||||
| Adjusted transportation and processing costs | $ | 3.98 | $ | 5.36 | $ | (1.38 | ) | |||||
| Transportation and processing costs deducted from oil and condensate, gas and NGL sales | (1.08 | ) | — | (1.08 | ) | |||||||
| Transportation and processing costs, as presented | $ | 2.90 | $ | 5.36 | $ | (2.46 | ) | |||||
The following tables present QEP's volumes and average prices for its open derivative positions as of April 20, 2018:
| Production Commodity Derivative Swaps | |||||||||
| Year | Index | Total Volumes | Average Swap Price per Unit |
||||||
| (in millions) | |||||||||
| Oil sales | (bbls | ) | ($/bbl | ) | |||||
| 2018 (April through December) | NYMEX WTI | 12.7 | $ | 52.48 | |||||
| 2019 | NYMEX WTI | 9.5 | $ | 52.66 | |||||
| Gas sales | (MMBtu | ) | ($/MMBtu | ) | |||||
| 2018 (May through December) | NYMEX HH | 71.7 | $ | 3.00 | |||||
| 2018 (July through December) | NYMEX HH | 1.8 | $ | 3.01 | |||||
| 2019 | NYMEX HH | 43.8 | $ | 2.86 | |||||
| Production Commodity Derivative Basis Swaps | |||||||||||
| Year | Index Less Differential | Index | Total Volumes | Weighted-Average Differential |
|||||||
| (in millions) | |||||||||||
| Oil sales | (bbls | ) | ($/bbl | ) | |||||||
| 2018 (April through December) | NYMEX WTI | Argus WTI Midland | 5.5 | $ | (1.06 | ) | |||||
| 2018 (July through December) | NYMEX WTI | Argus WTI Midland | 0.9 | $ | (0.71 | ) | |||||
| 2019 | NYMEX WTI | Argus WTI Midland | 4.7 | $ | (0.77 | ) | |||||
| Gas sales | (MMBtu | ) | ($/MMBtu | ) | |||||||
| 2018 (May through December) | NYMEX HH | IFNPCR | 4.9 | $ | (0.16 | ) | |||||