Full Year 2015 Highlights
- Reduced year-over-year capital expenditures by 41%, excluding acquisitions, while delivering record total production
- Increased year-over-year crude oil production by more than 14%
- Maintained strong liquidity, including $376 million of cash at year-end and undrawn revolving credit facility
- Achieved record estimated year-end proved crude oil reserves
2016 Capital Investment Plan
- Investing capital of $450 to $500 million, matched to forecasted cash flow
- Maintaining three to four QEP-operated rigs during 2016, with one each in Williston, Permian and Pinedale
- Forecasting flat crude oil production and a slight reduction in natural gas production compared with 2015
- Suspending dividend payments to preserve cash and provide additional financial flexibility
DENVER, Feb. 24, 2016 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported fourth quarter and full year 2015 financial and operating results. The Company reported a net loss of $38.6 million for the fourth quarter 2015, or $0.22 per diluted share, compared with net income of $665.9 million, or $3.72 per diluted share, in the fourth quarter 2014. For the year ended December 31, 2015, QEP reported a net loss of $149.4 million, or $0.85 per diluted share, compared with net income of $784.4 million, or $4.36 per diluted share, for the comparable 2014 period.
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, costs associated with the early extinguishment of debt, asset impairments and certain other non-cash and/or non-recurring items. Excluding these items, the Company's fourth quarter 2015 Adjusted Net Loss (a non-GAAP measure) was $1.8 million, or $0.01 per diluted share, compared with Adjusted Net Income of $38.6 million, or $0.22 per diluted share, in the fourth quarter 2014. For the year ended December 31, 2015, the Company’s Adjusted Net Income was $1.9 million, or $0.01 per diluted share, compared with Adjusted Net Income of $239.1 million, or $1.33 per diluted share, for 2014.
Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2015 was $254.0 million, compared with $386.3 million in the fourth quarter 2014. For the year ended December 31, 2015, the Company reported Adjusted EBITDA of $1,029.3 million compared with $1,483.3 million from continuing operations for 2014. The definition and reconciliations of Adjusted EBITDA and Adjusted Net Income to net income are provided within the financial tables of this release.
“Our high-quality, diversified E&P asset portfolio, combined with a year-end 2015 cash position of $376 million and an undrawn revolving credit facility, places QEP in an enviable position in today's challenging commodity price environment,” commented Chuck Stanley, Chairman, President and CEO of QEP Resources. “In the fourth quarter we continued to optimize production, increase operating efficiencies, reduce costs and allocate capital to the highest return assets in our portfolio."
“As a testament to our asset quality, we reported estimated 2015 year-end proved reserves of 3.6 trillion cubic feet of gas equivalent, an 8% decline from year-end 2014, despite a 47% and 40% decline in SEC year-end 2015 prices of crude oil and natural gas, respectively, from year-end 2014. We also achieved record estimated year-end proved crude oil reserves, and replaced 236% of total 2015 production, excluding price-related revisions."
“As we enter 2016, capital discipline remains the cornerstone of our corporate strategy. In response to current commodity prices, we have set a capital investment budget of $450 to $500 million, designed to match forecasted 2016 cash flow. The capital investment budget anticipates ramping down from nine QEP-operated rigs at the end of 2015 to three to four operated rigs for the remainder of the year, with one each on our Williston, Permian and Pinedale acreage. The budget also anticipates funding the completion of a portion of our inventory of drilled but not completed wells carried over from last year and provides flexibility for the addition of a fourth rig later in 2016. While we are reducing our 2016 capital program by over 50% compared with 2015, the combined benefits of lower well costs, continued improvements in new well productivity, and the quality of our assets should allow us to keep year-over-year oil production essentially flat, with natural gas production down slightly. In addition, we are suspending our $0.02 per quarter dividend to further bolster our liquidity. While the impact on our cash position is relatively small, we believe this is a prudent decision in this commodity price environment."
“Moving forward, we remain keenly focused on creating shareholder value through operational excellence, solid execution, technical innovation, and financial discipline. We will continue to actively manage our capital program to preserve our balance sheet, so we are in position to capitalize on our portfolio of top-tier assets when the commodity market improves,” concluded Stanley.
The “4Q 2015 Operations Update” presentation, which includes slides containing maps and other supporting materials referred to in this release, is posted on the Company’s website www.qepres.com.
QEP Financial Results Summary
| Adjusted EBITDA by Operating Segment (1) | |||||||||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
| (in millions) | |||||||||||||||||||||
| QEP Energy | $ | 254.1 | $ | 373.0 | (32 | )% | $ | 1,027.1 | $ | 1,437.0 | (29 | )% | |||||||||
| QEP Marketing and Other | (0.1 | ) | (6.9 | ) | 99 | % | 2.2 | 1.3 | 69 | % | |||||||||||
| Adjusted EBITDA from continuing operations | 254.0 | 366.1 | (31 | )% | 1,029.3 | 1,438.3 | (28 | )% | |||||||||||||
| Adjusted EBITDA from discontinued operations | — | 20.2 | (100 | )% | — | 144.4 | (100 | )% | |||||||||||||
| Adjusted EBITDA | $ | 254.0 | $ | 386.3 | (34 | )% | $ | 1,029.3 | $ | 1,582.7 | (35 | )% | |||||||||
| (1) See attached financial tables of this release for a reconciliation of Adjusted EBITDA to net income. | |||||||||||||||||||||
QEP Energy
- Adjusted EBITDA for the fourth quarter 2015 was $254.1 million, a 32% decrease from the fourth quarter 2014, primarily due to decreased average realized prices for crude oil, natural gas and NGL, partially offset by an increase in natural gas production.
- Capital investment (on an accrual basis) for the fourth quarter 2015, was $218.6 million, down $15.4 million from the third quarter 2015, excluding acquisitions. Capital investment (on an accrual basis) for the year ended December 31, 2015, was $1,007.4 million, down 41% compared with the full year 2014, excluding acquisitions.
- Net equivalent production decreased by 2% to 84.0 Bcfe in the fourth quarter 2015 compared with 85.9 Bcfe in the fourth quarter 2014. This decrease was primarily due to decreased crude oil and NGL production in the Williston Basin, partially offset by increased crude oil, NGL and natural gas production in the Permian Basin and increased natural gas production at Pinedale.
- Crude oil and NGL production decreased 2% and 27%, respectively, while natural gas production increased 4%, in the fourth quarter 2015 compared with the fourth quarter 2014. Fourth quarter 2015 crude oil volumes were impacted by completion related shut-ins in the Williston Basin, while NGL volumes were lower due to operating in ethane rejection.
- Crude oil and NGL production accounted for 67% of field-level revenues in the fourth quarter 2015. Field-level revenues decreased 43% in the fourth quarter 2015 compared with the fourth quarter 2014 due to lower crude oil and NGL prices and lower NGL volumes.
- During the full year 2015, the Company invested nearly $100 million to acquire various oil and gas properties, including additional interests in QEP-operated wells, in several of its core areas of operation. These acquisitions were partially offset by the sale of certain non-core assets.
- The Company has entered into additional crude oil and natural gas derivative contracts for 2016, 2017 and 2018 to help mitigate commodity price risk. See tables provided in this release for further details.
QEP Marketing & Other
- QEP Resources ended the fourth quarter 2015 with cash and cash equivalents of $376.1 million and no borrowings under its unsecured revolving credit facility. The credit facility was amended in the fourth quarter 2015. QEP's credit facility is not subject to semi-annual borrowing base redeterminations.
- General and administrative expense for the fourth quarter 2015 was $40.4 million, a decrease of 30% compared with the fourth quarter 2014. For the year ended December 31, 2015, general and administrative expense was $181.1 million, a decrease of over 11% compared with the prior year. Full year 2015 general and administrative expense reflects one time charges of $2.7 million related to workforce reductions, $5.0 million related to the closure of our Tulsa, Oklahoma office and $11.2 million related to a pension curtailment.
- Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing and QEP Energy. QEP Energy will market its own gas, oil and NGL production. In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts have been assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system in Northwest Louisiana. As a result, a majority of intercompany transactions will be eliminated, and the Company will have one reportable segment. The change in affiliate transactions will simplify our business processes and financial statements.
- QEP Resources suspended its cash dividend indefinitely in response to significant declines in crude oil, NGL and natural gas prices. The suspension of the dividend will allow the Company to preserve cash in the current commodity environment.
QEP 2016 Guidance
In response to the current commodity price environment QEP intends to reduce its capital budget for drilling and completions by over 50% compared with 2015. Due to efficiency gains, strong well performance and ongoing cost reduction initiatives, the Company expects to see essentially flat year-over-year crude oil production in 2016. The Company's guidance anticipates that its working rig count will decline from nine at year-end 2015 to approximately three to four rigs, with one each in the Williston and Permian basins and Pinedale, respectively, by the beginning of the second quarter 2016.
QEP Resources initial full year 2016 guidance and related assumptions are shown below. The Company’s guidance assumes no asset acquisitions or divestitures, and that QEP will not recover ethane from its produced gas for the entire year.
| Initial 2016 Guidance | |||
| 2016 | |||
| Current Forecast | |||
| Oil production (MMBbl) | 18.5 - 20.5 | ||
| NGL production (MMBbl) | 4 - 5 | ||
| Natural gas production (Bcf) | 165 - 175 | ||
| Total equivalent production (Bcfe) | 300 - 328 | ||
| Lease operating and transportation expense (per Mcfe) | $1.60 - $1.70 | ||
| Depletion, depreciation and amortization (per Mcfe) | $3.00 - $3.30 | ||
| Production and property taxes, % of field-level revenue | 8.5 | % | |
| Figures below in millions | |||
| General and administrative expense (1) | $150 - $160 | ||
| Capital investment (excluding acquisitions) | $450 - $500 | ||
| (1) Forecasted general and administrative expense includes approximately $35.0 million of non-cash expenses primarily related to share based compensation. | |||
Estimated Proved Reserves
QEP Energy's estimated proved reserves totaled 3.6 Tcfe at December 31, 2015, down 8% from year-end 2014, primarily due to the net impact of lower crude oil, natural gas and NGL prices. Approximately 42% of total proved reserves at year-end 2015 were crude oil and NGL compared with 41% at year-end 2014. Proved developed reserves were 2.1 Tcfe, or 58%, of total estimated proved reserves at year-end 2015. Extensions and discoveries were 1.1 Tcfe, driven primarily by the Company's development activities in the Williston, Permian and Uinta basins. A reconciliation of reported quantities of estimated proved reserves is summarized in the table below:
| Natural Gas | Oil | NGL | Natural Gas Equivalents | |||||||||
| (Bcf) | (MMbbl) | (MMbbl) | (Bcfe)(1) | |||||||||
| Balance at December 31, 2014 | 2,317.2 | 172.5 | 96.6 | 3,931.9 | ||||||||
| Revisions of previous estimates(2) | (463.8 | ) | (47.0 | ) | (55.3 | ) | (1,077.9 | ) | ||||
| Extensions and discoveries | 467.7 | 85.6 | 21.8 | 1,111.9 | ||||||||
| Purchase of reserves in place | 3.2 | 2.0 | 0.6 | 18.7 | ||||||||
| Sale of reserves in place | (34.3 | ) | (0.4 | ) | (0.2 | ) | (37.6 | ) | ||||
| Production | (181.1 | ) | (19.6 | ) | (4.7 | ) | (326.8 | ) | ||||
| Balance at December 31, 2015 | 2,108.9 | 193.1 | 58.8 | 3,620.2 | ||||||||
| (1) Oil and NGL are converted to natural gas equivalents at the ratio of one barrel of crude oil, condensate or NGL to six Mcf of natural gas equivalent. | ||||||||||||
| (2) Price-related negative revisions totaled 756.9 Bcfe | ||||||||||||
Details on the reported quantities of estimated year-end 2015 and 2014 proved reserves presented by operating area, proved reserve category and percentage of total estimated proved reserves comprised of crude oil and NGL (liquids) are as follows:
| Total (in Bcfe) | % of total | PUD % | liquids % | |||||||||
| For the year ended December 31, 2015 | ||||||||||||
| Northern Region | ||||||||||||
| Pinedale | 1,125.0 | 31 | % | 27 | % | 13 | % | |||||
| Williston Basin | 1,085.7 | 30 | % | 39 | % | 86 | % | |||||
| Uinta Basin | 558.9 | 16 | % | 55 | % | 18 | % | |||||
| Other Northern | 74.4 | 2 | % | — | % | 8 | % | |||||
| Southern Region | ||||||||||||
| Haynesville/Cotton Valley | 396.5 | 11 | % | 57 | % | — | % | |||||
| Permian Basin | 374.0 | 10 | % | 66 | % | 87 | % | |||||
| Midcontinent | 5.7 | — | % | — | % | 32 | % | |||||
| Total QEP Energy | 3,620.2 | 100 | % | 42 | % | 42 | % | |||||
| For the year ended December 31, 2014 | ||||||||||||
| Northern Region | ||||||||||||
| Pinedale | 1,450.1 | 37 | % | 41 | % | 24 | % | |||||
| Williston Basin | 858.9 | 22 | % | 40 | % | 88 | % | |||||
| Uinta Basin | 623.0 | 16 | % | 48 | % | 32 | % | |||||
| Other Northern | 94.0 | 2 | % | — | % | 11 | % | |||||
| Southern Region | ||||||||||||
| Haynesville/Cotton Valley | 493.9 | 13 | % | 57 | % | — | % | |||||
| Permian Basin | 375.7 | 10 | % | 58 | % | 78 | % | |||||
| Midcontinent | 36.3 | — | % | — | % | 19 | % | |||||
| Total QEP Energy | 3,931.9 | 100 | % | 44 | % | 41 | % | |||||
Operations Summary
The table below presents a summary of QEP-operated and non-operated well completions for the year ended December 31, 2015:
| Operated Completions | Non-operated Completions | ||||||||||||||||||||||
| Three Months Ended December 31, 2015 | Year Ended December 31, 2015 | Three Months Ended December 31, 2015 | Year Ended December 31, 2015 | ||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
| Northern Region | |||||||||||||||||||||||
| Pinedale | 24 | 14.4 | 107 | 68.1 | — | — | — | — | |||||||||||||||
| Williston Basin | 10 | 7.8 | 70 | 55.0 | 16 | 0.5 | 84 | 4.7 | |||||||||||||||
| Uinta Basin | — | — | 11 | 11.0 | — | — | 19 | 0.2 | |||||||||||||||
| Other Northern | — | — | 4 | 4.0 | — | — | — | — | |||||||||||||||
| Southern Region | |||||||||||||||||||||||
| Haynesville/Cotton Valley | — | — | — | — | 4 | 0.3 | 24 | 3.2 | |||||||||||||||
| Permian Basin | 5 | 4.7 | 36 | 31.6 | 1 | 0.6 | 2 | 0.9 | |||||||||||||||
| Midcontinent | — | — | — | — | — | — | 4 | 0.1 | |||||||||||||||
Williston Basin
Williston Basin net production averaged approximately 51.6 Mboed (90% liquids) during the fourth quarter 2015, a decrease of 4% compared with both the third quarter 2015 and fourth quarter 2014. The Company completed and turned to sales 10 gross operated wells during the quarter (average working interest 78%), all in South Antelope. Williston Basin production was impacted during the quarter by offset completion activity, which resulted in shut-ins and curtailments of existing wells. The Company also participated in 16 gross outside-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 3%). (See Slide 6)
The Company's five high-density infill pilot wells spaced at 400- and 600-foot intervals in the Middle Bakken and the Three Forks formations that were initially completed and turned to sales in the second quarter 2015 continue to perform strongly. During the fourth quarter, the Company turned to sales five additional high-density infill pilot wells spaced at 600 feet which brings the total wells turned to sales within the pilot area to 21.
QEP also continued to conduct tests on the second bench of the Three Forks Formation, with four wells completed in this zone recently turned to sales with an average 24-hour IP of 2,665 Boed. Finally, during the fourth quarter the Company turned to sales its first third bench Three Forks test with a 24-hour IP of 3,058 Boed. The well continues to show promising early-time performance, closely tracking cumulative production performance of first and second bench wells. (See Slides 7-10)
As the Company continues infill development, the anticipated well pod size (well pods are clusters of closely-spaced wellheads) is expected to increase from a current average of four wells per pod to as many as 12 wells per pod. Larger well pods will result in increased latency between drilling and completion operations as more wells are temporarily “trapped” under a drilling rig until all wells on a pod are finished, the rig is removed, and completion operations can begin, and greater downtime for offset fracture stimulations, resulting in more variability in production volumes from the Company's Williston Basin assets in the future.
At the end of the fourth quarter, QEP had 24 gross operated wells waiting on completion (comprised of 21 in South Antelope and three at Ft. Berthold, average working interest 95%) in the Williston Basin and three operated rigs running in South Antelope. In addition, the Company had interest in 19 gross non-operated wells waiting on completion (average working interest 5%) at the end of the fourth quarter.
Current average gross QEP-operated drilled and completed authorization for expenditure ("AFE") well costs are $6.0 million on South Antelope, with costs associated with facilities and artificial lift adding approximately $0.8 million per well on average. The Company expects the operated rig count in South Antelope to drop to one rig by the beginning of the second quarter 2016.
Slides 5-11 depict QEP Energy's acreage and activity in the Williston Basin.
Permian Basin
Permian Basin net production averaged 13.8 Mboed (84% liquids) during the fourth quarter 2015, a 5% increase over the third quarter 2015 and a 42% increase over the fourth quarter 2014. QEP completed and turned to sales five gross-operated horizontal wells in the fourth quarter 2015 (average working interest 94%). One well targeted the Spraberry Shale and four targeted the Middle Spraberry. Four of the five wells reached peak production during the quarter; the University 7-1302 H2 SS, completed in the Spraberry Shale, achieved a peak 24-hour IP rate of 1,753 Boed and the Mabee C H19 MS, Mabee C H20 MS, and University 7-1302 H1 MS wells, all targeting the Middle Spraberry achieving peak 24-hour rates of 863 Boed, 961 Boed, and 1,115 Boed, respectively.
At the end of the fourth quarter, QEP had four gross-operated horizontal wells (two Spraberry Shale and two Middle Spraberry) waiting on completion (average working interest 98%) and two operated rigs in the Permian Basin drilling horizontal targets.
Current average gross QEP-operated drilled and completed AFE well costs are $5.7 million for Spraberry wells, with costs associated with facilities and artificial lift adding approximately $0.7 million per well, on average. The Company expects the operated rig count in the Permian Basin to drop to one rig by the beginning of the second quarter 2016.
Slides 12-15 depict QEP Energy's acreage and activity in the Permian Basin.
Pinedale
Pinedale net production averaged 304 MMcfed (14% liquids), a new natural gas production record for QEP, during the fourth quarter 2015. This represented a 6% increase over the third quarter 2015 and a 7% increase over the fourth quarter 2014. The Company completed and turned to sales 24 gross-operated Pinedale wells in the quarter.
At the end of the fourth quarter, QEP had 20 gross-operated Pinedale wells waiting on completion (average working interest 63%) and three operated rigs running in Pinedale.
Current average gross QEP-operated drilled and completed AFE well costs are $2.9 million in Pinedale, with costs associated with facilities and plunger lift adding approximately $0.2 million per well, on average. The Company expects operated rig count in Pinedale to drop to one rig by the beginning of the second quarter 2016.
Slide 16 depicts QEP Energy's acreage and activity at Pinedale.
Uinta Basin
Uinta Basin net production averaged 71 MMcfed (21% liquids), during the fourth quarter 2015, of which 43 MMcfed (10% liquids) was from the Lower Mesaverde play.
QEP’s continued focus on drilling and completion optimization is yielding encouraging results in the Lower Mesaverde play. The Company's most recent horizontal well exhibited strong peak production early in the fourth quarter while drilling days and completed well costs continued to decrease. Production performance from the pad of eight directionally drilled vertical wells targeting the Lower Mesaverde (completed at the end of the second quarter 2015) continues to be solid. These wells have achieved over 3.5 Bcfe gross aggregate cumulative production after 224 days online (post refrigeration-processing). The Company believes it has an extensive inventory of vertical and horizontal well locations in the Lower Mesaverde play, and recent results continue to further de-risk this multi-Tcfe resource.
At the end of the fourth quarter, QEP had one rig active in the Uinta Basin drilling an eight well pad of directional vertical wells targeting the Lower Mesaverde play. The Company expects to operate no rigs in the Uinta Basin once QEP has completed drilling on the current eight well pad.
Slide 17 depicts QEP Energy's activity in the Red Wash Lower Mesaverde play in the Uinta Basin.
Fourth Quarter 2015 and Full Year Results Conference Call
QEP Resources' management will discuss fourth quarter and full year 2015 results in a conference call on Thursday, February 25, 2016, beginning at 9:00 a.m. EST. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website at www.qepres.com immediately after the call through March 25, 2015, 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 #13628460. In addition, QEP’s slides for the fourth quarter 2015, 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 at www.qepres.com.
About QEP Resources, Inc.
QEP Resources, Inc. (NYSE:QEP) is a leading independent natural gas and crude oil exploration and production company focused in two major regions: the Northern Region (primarily the Rockies and the Williston Basin) and the Southern Region (primarily Texas and Louisiana) of the United States. For more information, visit QEP Resources' website at: www.qepres.com.
Forward-Looking Statements
This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions. Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include statements regarding: our 2016 Capital Investment Plan, including amount of planned capital expenditures, the number and location of drilling rigs to be deployed, anticipated production levels and the suspension of dividend payments; our high quality, diversified E&P asset portfolio; our liquidity; our focus on capital discipline; plans to match spending with anticipated cash flows; funding the completion in 2016 of a portion of our wells drilled but not completed in 2015; adding a fourth rig during 2016; expected gross completed well costs and additional costs for facilities and artificial lift; variability in production volumes from the Williston Basin and factors contributing to such variability; forecasted production, lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, production and property taxes and capital investment for 2015 and related assumptions for such guidance; plans to reject ethane in 2016; drilling and completion optimization; operational excellence; solid execution; technical innovation; preservation of our balance sheet; estimated reserves; our extensive inventory of drilling locations; simplification of our business processes and financial statements by eliminating certain intercompany transactions; preservation of cash; the pension curtailment loss; and the importance 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: 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 (OPEC), including the ability of members of OPEC to agree to and maintain oil price and production controls and the ability of Iran to market its oil following the lifting of trade sanctions; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; impact of new laws and regulations, including regulations regarding the flaring of natural gas, the use of hydraulic fracture stimulation and the implementation of the Dodd-Frank Act; impact of U.S. dollar exchange rates on oil, NGL and natural gas prices; elimination of federal income tax deductions for oil and gas exploration and development; imposition of a federal tax on each barrel of oil produced in the United States; 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, 2015. 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.
Disclosures regarding non-proved reserves
The Securities and Exchange Commission (SEC) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves; however, QEP has made no such disclosures in its filings with the SEC. Estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially more risks of actually being realized. Actual quantities that may be ultimately recovered from QEP’s interests may differ substantially from the reserve estimates contained in this release. Investors are urged to closely consider the disclosures and risk factors about the Company’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2015, and in other reports on file with the SEC.
| QEP RESOURCES, INC. CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||
| REVENUES | (in millions, except per share amounts) | ||||||||||||||
| Gas sales | $ | 105.2 | $ | 167.2 | $ | 468.5 | $ | 776.4 | |||||||
| Oil sales | 193.3 | 327.5 | 834.2 | 1,368.5 | |||||||||||
| NGL sales | 18.3 | 44.0 | 80.0 | 223.3 | |||||||||||
| Other revenues | 2.7 | 6.0 | 15.1 | 11.1 | |||||||||||
| Purchased gas and oil sales (1) | 148.8 | 212.4 | 620.8 | 913.9 | |||||||||||
| Total Revenues | 468.3 | 757.1 | 2,018.6 | 3,293.2 | |||||||||||
| OPERATING EXPENSES | |||||||||||||||
| Purchased gas and oil expense (1) | 151.7 | 213.2 | 626.8 | 910.1 | |||||||||||
| Lease operating expense | 63.2 | 63.1 | 238.8 | 240.1 | |||||||||||
| Gas, oil and NGL transportation and other handling costs | 75.1 | 79.1 | 291.3 | 277.6 | |||||||||||
| Gathering and other expense | 1.4 | 1.9 | 5.8 | 6.7 | |||||||||||
| General and administrative | 40.4 | 57.4 | 181.1 | 204.4 | |||||||||||
| Production and property taxes | 26.9 | 44.4 | 117.6 | 205.2 | |||||||||||
| Depreciation, depletion and amortization | 231.8 | 282.2 | 881.1 | 994.7 | |||||||||||
| Exploration expenses | — | 5.2 | 2.7 | 9.9 | |||||||||||
| Impairment | 20.1 | 1,139.6 | 55.6 | 1,143.2 | |||||||||||
| Total Operating Expenses | 610.6 | 1,886.1 | 2,400.8 | 3,991.9 | |||||||||||
| Net gain (loss) from asset sales | (2.3 | ) | 61.7 | 4.6 | (148.6 | ) | |||||||||
| OPERATING INCOME (LOSS) | (144.6 | ) | (1,067.3 | ) | (377.6 | ) | (847.3 | ) | |||||||
| Realized and unrealized gains (losses) on derivative contracts | 108.7 | 376.5 | 277.2 | 363.3 | |||||||||||
| Interest and other income | 1.5 | 5.0 | 3.0 | 12.8 | |||||||||||
| Income from unconsolidated affiliates | — | 0.1 | — | 0.3 | |||||||||||
| Loss from early extinguishment of debt | — | (2.0 | ) | — | (2.0 | ) | |||||||||
| Interest expense | (36.2 | ) | (40.7 | ) | (145.6 | ) | (169.1 | ) | |||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (70.6 | ) | (728.4 | ) | (243.0 | ) | (642.0 | ) | |||||||
| Income tax (provision) benefit | 32.0 | 258.6 | 93.6 | 232.5 | |||||||||||
| NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (38.6 | ) | (469.8 | ) | (149.4 | ) | (409.5 | ) | |||||||
| Net income from discontinued operations, net of income tax | — | 1,135.7 | — | 1,193.9 | |||||||||||
| NET INCOME (LOSS) | $ | (38.6 | ) | $ | 665.9 | $ | (149.4 | ) | $ | 784.4 | |||||
| Earnings (loss) per common share | |||||||||||||||
| Basic from continuing operations | $ | (0.22 | ) | $ | (2.62 | ) | $ | (0.85 | ) | $ | (2.28 | ) | |||
| Basic from discontinued operations | — | 6.34 | — | 6.64 | |||||||||||
| Basic total | $ | (0.22 | ) | $ | 3.72 | $ | (0.85 | ) | $ | 4.36 | |||||
| Diluted from continuing operations | $ | (0.22 | ) | $ | (2.62 | ) | $ | (0.85 | ) | $ | (2.28 | ) | |||
| Diluted from discontinued operations | — | 6.34 | — | $ | 6.64 | ||||||||||
| Diluted total | $ | (0.22 | ) | $ | 3.72 | $ | (0.85 | ) | $ | 4.36 | |||||
| Weighted-average common shares outstanding | |||||||||||||||
| Used in basic calculation | 176.7 | 179.0 | 176.6 | 179.8 | |||||||||||
| Used in diluted calculation | 176.7 | 179.0 | 176.6 | 179.8 | |||||||||||
| Dividends per common share | $ | 0.02 | $ | 0.02 | $ | 0.08 | $ | 0.08 | |||||||
| (1) In the fourth quarter of 2015, the Company determined that certain transactions that had been reported on a gross basis and included in "Purchased gas and oil sales" and "Purchased gas and oil expense" on the Consolidated Statement of Operations for certain periods in 2014 and the first three quarters of 2015 should have been reported net, as the transactions were with the same counterparty and were entered into in contemplation of one another. The Company revised its financial statements to reflect the net accounting treatment and assessed the cumulative impact of the revisions on each period affected. The revisions had no effect on the Company’s operating income, net income, earnings per share or cash flows. The Company determined that the impact of the change from gross to net accounting was not material, either individually or in the aggregate, to previously issued financial statements. The Company has, however, recast its Consolidated Statement of Operations for the year ended December 31, 2014, to report “Purchased gas and oil sales” and “Purchased gas and oil expense” on a net basis to conform to presentation for the year ended December 31, 2015. | |||||||||||||||
| QEP RESOURCES, INC. CONSOLIDATED BALANCE SHEETS | |||||||
| December 31, 2015 | December 31, 2014 | ||||||
| ASSETS | (in millions) | ||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 376.1 | $ | 1,160.1 | |||
| Accounts receivable, net | 278.2 | 441.9 | |||||
| Income tax receivable | 87.3 | — | |||||
| Fair value of derivative contracts | 146.8 | 339.0 | |||||
| Gas, oil and NGL inventories, at lower of average cost or market | 13.3 | 13.7 | |||||
| Prepaid expenses and other | 30.1 | 46.8 | |||||
| Total Current Assets | 931.8 | 2,001.5 | |||||
| Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
| Proved properties | 13,314.9 | 12,278.7 | |||||
| Unproved properties | 691.0 | 825.2 | |||||
| Marketing and other | 297.9 | 293.8 | |||||
| Materials and supplies | 38.5 | 54.3 | |||||
| Total Property, Plant and Equipment | 14,342.3 | 13,452.0 | |||||
| Less Accumulated Depreciation, Depletion and Amortization | |||||||
| Exploration and production | 6,870.2 | 6,153.0 | |||||
| Marketing and other | 87.5 | 67.8 | |||||
| Total Accumulated Depreciation, Depletion and Amortization | 6,957.7 | 6,220.8 | |||||
| Net Property, Plant and Equipment | 7,384.6 | 7,231.2 | |||||
| Fair value of derivative contracts | 23.2 | 9.9 | |||||
| Other noncurrent assets | 85.9 | 44.2 | |||||
| TOTAL ASSETS | $ | 8,425.5 | $ | 9,286.8 | |||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities | |||||||
| Checks outstanding in excess of cash balances | $ | 29.8 | $ | 54.7 | |||
| Accounts payable and accrued expenses | 351.7 | 575.4 | |||||
| Income taxes payable | — | 532.1 | |||||
| Production and property taxes | 46.1 | 61.7 | |||||
| Interest payable | 36.4 | 36.4 | |||||
| Fair value of derivative contracts | 0.8 | — | |||||
| Deferred income taxes | — | 84.5 | |||||
| Current portion of long-term debt | 176.8 | — | |||||
| Total Current Liabilities | 641.6 | 1,344.8 | |||||
| Long-term debt | 2,042.0 | 2,218.1 | |||||
| Deferred income taxes | 1,479.8 | 1,362.7 | |||||
| Asset retirement obligations | 204.9 | 193.8 | |||||
| Fair value of derivative contracts | 4.0 | — | |||||
| Other long-term liabilities | 105.3 | 92.1 | |||||
| Commitments and Contingencies | |||||||
| EQUITY | |||||||
| Common stock - par value $0.01 per share; 500.0 million shares authorized; 177.3 million and 176.2 million shares issued, respectively | 1.8 | 1.8 | |||||
| Treasury stock - 0.5 million and 0.8 million shares, respectively | (14.6 | ) | (25.4 | ) | |||
| Additional paid-in capital | 554.8 | 535.3 | |||||
| Retained earnings | 3,418.3 | 3,587.9 | |||||
| Accumulated other comprehensive income (loss) | (12.4 | ) | (24.3 | ) | |||
| Total Common Shareholders' Equity | 3,947.9 | 4,075.3 | |||||
| TOTAL LIABILITIES AND EQUITY | $ | 8,425.5 | $ | 9,286.8 | |||
| QEP RESOURCES, INC. CONSOLIDATED CASH FLOWS | |||||||
| Year Ended | |||||||
| December 31, | |||||||
| 2015 | 2014 | ||||||
| (in millions) | |||||||
| OPERATING ACTIVITIES | |||||||
| Net income (loss) | $ | (149.4 | ) | $ | 784.4 | ||
| Net income attributable to noncontrolling interest | — | 21.6 | |||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
| Depreciation, depletion and amortization | 881.1 | 1,040.6 | |||||
| Deferred income taxes | 25.3 | (84.1 | ) | ||||
| Impairment | 55.6 | 1,143.2 | |||||
| Share-based compensation | 34.7 | 27.2 | |||||
| Pension curtailment | 11.2 | — | |||||
| Amortization of debt issuance costs and discounts | 6.2 | 6.7 | |||||
| Net loss (gain) from asset sales | (4.6 | ) | (1,644.8 | ) | |||
| Income from unconsolidated affiliates | — | (5.2 | ) | ||||
| Distributions from unconsolidated affiliates and other | — | 9.4 | |||||
| Non-cash loss on early extinguishment of debt | — | 4.4 | |||||
| Unrealized (gains) losses on marketable securities | 0.2 | — | |||||
| Unrealized (gains) losses on derivative contracts | 183.7 | (374.4 | ) | ||||
| Changes in operating assets and liabilities | (562.7 | ) | 613.5 | ||||
| Net Cash Provided by Operating Activities | 481.3 | 1,542.5 | |||||
| INVESTING ACTIVITIES | |||||||
| Property acquisitions | (98.3 | ) | (960.5 | ) | |||
| Property, plant and equipment, including dry hole exploratory well expense | (1,141.1 | ) | (1,765.9 | ) | |||
| Proceeds from disposition of assets | 21.8 | 3,296.6 | |||||
| Acquisition deposit held in escrow | — | 50.0 | |||||
| Other investing activities | — | (42.0 | ) | ||||
| Net Cash Provided by (Used in) Investing Activities | (1,217.6 | ) | 578.2 | ||||
| FINANCING ACTIVITIES | |||||||
| Checks outstanding in excess of cash balances | (24.9 | ) | (54.4 | ) | |||
| Long-term debt issued | — | 300.0 | |||||
| Long-term debt issuance costs paid | (2.6 | ) | (9.3 | ) | |||
| Long-term debt repaid | — | (600.0 | ) | ||||
| Proceeds from credit facility | — | 5,455.0 | |||||
| Repayments of credit facility | — | (5,935.0 | ) | ||||
| Common stock repurchased and retired | — | (99.7 | ) | ||||
| Treasury stock repurchases | (2.7 | ) | (6.2 | ) | |||
| Other capital contributions | (0.2 | ) | 6.0 | ||||
| Dividends paid | (14.1 | ) | (14.6 | ) | |||
| Excess tax (provision) benefit on share-based compensation | (3.2 | ) | (0.5 | ) | |||
| Distribution to noncontrolling interest | — | (31.9 | ) | ||||
| Net Cash Provided by (Used in) Financing Activities | (47.7 | ) | (990.6 | ) | |||
| Change in cash and cash equivalents | (784.0 | ) | 1,130.1 | ||||
| Beginning cash and cash equivalents | 1,160.1 | 30.0 | |||||
| Ending cash and cash equivalents | $ | 376.1 | $ | 1,160.1 | |||
| QEP Energy - Production by Region | |||||||||||||||||
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
| (in Bcfe) | |||||||||||||||||
| Northern Region | |||||||||||||||||
| Pinedale | 28.0 | 26.3 | 6 | % | 101.0 | 98.9 | 2 | % | |||||||||
| Williston Basin | 28.5 | 29.8 | (4 | )% | 112.3 | 91.4 | 23 | % | |||||||||
| Uinta Basin | 6.5 | 7.5 | (13 | )% | 29.5 | 27.3 | 8 | % | |||||||||
| Other Northern | 2.8 | 2.7 | 4 | % | 10.6 | 10.6 | — | % | |||||||||
| Total Northern Region | 65.8 | 66.3 | (1 | )% | 253.4 | 228.2 | 11 | % | |||||||||
| Southern Region | |||||||||||||||||
| Haynesville/Cotton Valley | 10.3 | 11.0 | (6 | )% | 43.6 | 49.9 | (13 | )% | |||||||||
| Permian | 7.6 | 5.4 | 41 | % | 26.0 | 15.8 | 65 | % | |||||||||
| Midcontinent | 0.3 | 3.2 | (91 | )% | 3.8 | 28.8 | (87 | )% | |||||||||
| Total Southern Region | 18.2 | 19.6 | (7 | )% | 73.4 | 94.5 | (22 | )% | |||||||||
| Total production | 84.0 | 85.9 | (2 | )% | 326.8 | 322.7 | 1 | % | |||||||||
| QEP Energy - Total Production | |||||||||||||||||
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
| QEP Energy Production Volumes | |||||||||||||||||
| Gas (Bcf) | 46.0 | 44.4 | 4 | % | 181.1 | 179.3 | 1 | % | |||||||||
| Oil (Mbbl) | 5,062.9 | 5,181.5 | (2 | )% | 19,582.3 | 17,146.5 | 14 | % | |||||||||
| NGL (Mbbl) | 1,272.0 | 1,751.3 | (27 | )% | 4,704.3 | 6,769.1 | (31 | )% | |||||||||
| Total production (Bcfe) | 84.0 | 85.9 | (2 | )% | 326.8 | 322.7 | 1 | % | |||||||||
| Average daily production (MMcfe) | 913.0 | 933.2 | (2 | )% | 895.3 | 884.0 | 1 | % | |||||||||
| QEP Energy - Prices | |||||||||||||||||||||
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
| Gas (per Mcf) | |||||||||||||||||||||
| Average field-level price | $ | 2.29 | $ | 3.78 | $ | 2.59 | $ | 4.33 | |||||||||||||
| Commodity derivative impact | 0.75 | 0.15 | 0.57 | (0.09 | ) | ||||||||||||||||
| Net realized price | $ | 3.04 | $ | 3.93 | (23 | )% | $ | 3.16 | $ | 4.24 | (25 | )% | |||||||||
| Oil (per bbl) | |||||||||||||||||||||
| Average field-level price | $ | 38.16 | $ | 63.21 | $ | 42.59 | $ | 79.79 | |||||||||||||
| Commodity derivative impact | 21.41 | 12.71 | 18.06 | 0.92 | |||||||||||||||||
| Net realized price | $ | 59.57 | $ | 75.92 | (22 | )% | $ | 60.65 | $ | 80.71 | (25 | )% | |||||||||
| NGL (per bbl) | |||||||||||||||||||||
| Average field-level price | $ | 14.41 | $ | 25.15 | $ | 16.98 | $ | 32.95 | |||||||||||||
| Commodity derivative impact | — | — | — | — | |||||||||||||||||
| Net realized price | $ | 14.41 | $ | 25.15 | (43 | )% | $ | 16.98 | $ | 32.95 | (48 | )% | |||||||||
| Average net equivalent price (per Mcfe) | |||||||||||||||||||||
| Average field-level price | $ | 3.77 | $ | 6.28 | $ | 4.23 | $ | 7.34 | |||||||||||||
| Commodity derivative impact | 1.70 | 0.84 | 1.40 | (0.01 | ) | ||||||||||||||||
| Net realized price | $ | 5.47 | $ | 7.12 | (23 | )% | $ | 5.63 | $ | 7.33 | (23 | )% | |||||||||
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| (per Mcfe) | |||||||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
| Depreciation, depletion and amortization | $ | 2.73 | $ | 3.26 | (16 | )% | $ | 2.66 | $ | 3.05 | (13 | )% | |||||||||
| Lease operating expense | 0.75 | 0.74 | 1 | % | 0.73 | 0.74 | (1 | )% | |||||||||||||
| Gas, oil and NGL transportation and other handling costs | 0.92 | 0.93 | (1 | )% | 0.92 | 0.90 | 2 | % | |||||||||||||
| Production taxes | 0.32 | 0.52 | (38 | )% | 0.35 | 0.63 | (44 | )% | |||||||||||||
| Total Operating Expenses | $ | 4.72 | $ | 5.45 | (13 | )% | $ | 4.66 | $ | 5.32 | (12 | )% | |||||||||
QEP RESOURCES, INC.
NON-GAAP MEASURES
Adjusted EBITDA
This release contains references to the non-GAAP measure of Adjusted EBITDA. Management believes Adjusted EBITDA is an important measure of the Company's financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. 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 non-cash and/or non-recurring items. The following tables reconcile net income to Adjusted EBITDA:
| QEP Energy | QEP Marketing & Other (1) | Continuing Operations | Discontinued Operations | QEP Consolidated | |||||||||||||||
| Three Months Ended December 31, 2015 | (in millions) | ||||||||||||||||||
| Net income (loss) | $ | (51.0 | ) | $ | 12.4 | $ | (38.6 | ) | $ | — | $ | (38.6 | ) | ||||||
| Unrealized gains on derivative contracts | 35.4 | 0.3 | 35.7 | — | 35.7 | ||||||||||||||
| Net (gain) loss from asset sales | 2.2 | 0.1 | 2.3 | — | 2.3 | ||||||||||||||
| Interest and other income | (1.4 | ) | (0.1 | ) | (1.5 | ) | — | (1.5 | ) | ||||||||||
| Income tax provision (benefit) | (32.7 | ) | 0.7 | (32.0 | ) | — | (32.0 | ) | |||||||||||
| Interest expense | 52.3 | (16.1 | ) | 36.2 | — | 36.2 | |||||||||||||
| Depreciation, depletion and amortization | 229.2 | 2.6 | 231.8 | — | 231.8 | ||||||||||||||
| Impairment | 20.1 | — | 20.1 | — | 20.1 | ||||||||||||||
| Exploration expenses | — | — | — | — | — | ||||||||||||||
| Adjusted EBITDA | $ | 254.1 | $ | (0.1 | ) | $ | 254.0 | $ | — | $ | 254.0 | ||||||||
| Three Months Ended December 31, 2014 | |||||||||||||||||||
| Net income (loss) | $ | (472.9 | ) | $ | 3.1 | $ | (469.8 | ) | $ | 1,135.7 | $ | 665.9 | |||||||
| Unrealized losses on derivative contracts | (304.4 | ) | (4.1 | ) | (308.5 | ) | — | (308.5 | ) | ||||||||||
| Net (gain) loss from asset sales | (61.7 | ) | — | (61.7 | ) | (1,793.5 | ) | (1,855.2 | ) | ||||||||||
| Interest and other income | (4.4 | ) | (0.6 | ) | (5.0 | ) | (0.3 | ) | (5.3 | ) | |||||||||
| Income tax provision (benefit) | (255.9 | ) | (2.7 | ) | (258.6 | ) | 675.4 | 416.8 | |||||||||||
| Interest expense (income) (2) | 47.8 | (7.1 | ) | 40.7 | 0.6 | 41.3 | |||||||||||||
| Loss on early extinguishment of debt | — | 2.0 | 2.0 | 2.4 | 4.4 | ||||||||||||||
| Depreciation, depletion and amortization (3) | 279.7 | 2.5 | 282.2 | (0.1 | ) | 282.1 | |||||||||||||
| Impairment | 1,139.6 | — | 1,139.6 | — | 1,139.6 | ||||||||||||||
| Exploration expenses | 5.2 | — | 5.2 | — | 5.2 | ||||||||||||||
| Adjusted EBITDA | $ | 373.0 | $ | (6.9 | ) | $ | 366.1 | $ | 20.2 | $ | 386.3 | ||||||||
| (1) Includes intercompany eliminations. | |||||||||||||||||||
| (2) Excludes noncontrolling interest's share of $0.4 million of during the three months ended December 31, 2014, of interest expense attributable to QEP Midstream Partners, L.P. (QEP Midstream), divested by the Company in December 2014 as part of the sale of our midstream assets. | |||||||||||||||||||
| (3) Excludes noncontrolling interests' share of $2.7 million during the three months ended December 31, 2014, of depreciation, depletion and amortization attributable to QEP Midstream and Rendezvous Gas Services, L.L.C., also divested by the Company in December 2014 as part of the sale of our midstream assets. | |||||||||||||||||||
| QEP Energy | QEP Marketing & Other (1) | Continuing Operations | Discontinued Operations | QEP Consolidated | |||||||||||||||
| For the Year Ended December 31, 2015 | (in millions) | ||||||||||||||||||
| Net income (loss) | $ | (182.9 | ) | $ | 33.5 | $ | (149.4 | ) | $ | — | $ | (149.4 | ) | ||||||
| Unrealized gains on derivative contracts | 182.9 | 0.8 | 183.7 | — | 183.7 | ||||||||||||||
| Net (gain) loss from asset sales | (9.7 | ) | 5.1 | (4.6 | ) | — | (4.6 | ) | |||||||||||
| Interest and other income | (1.9 | ) | (1.1 | ) | (3.0 | ) | — | (3.0 | ) | ||||||||||
| Income tax provision (benefit) | (105.9 | ) | 12.3 | (93.6 | ) | — | (93.6 | ) | |||||||||||
| Interest expense (income) | 204.5 | (58.9 | ) | 145.6 | — | 145.6 | |||||||||||||
| Pension curtailment loss (2) | 11.0 | 0.2 | 11.2 | — | 11.2 | ||||||||||||||
| Depreciation, depletion and amortization | 870.8 | 10.3 | 881.1 | — | 881.1 | ||||||||||||||
| Impairment | 55.6 | — | 55.6 | — | 55.6 | ||||||||||||||
| Exploration expenses | 2.7 | — | 2.7 | — | 2.7 | ||||||||||||||
| Adjusted EBITDA | $ | 1,027.1 | $ | 2.2 | $ | 1,029.3 | $ | — | $ | 1,029.3 | |||||||||
| For the Year Ended December 31, 2014 | |||||||||||||||||||
| Net income (loss) | $ | (432.5 | ) | $ | 23.0 | $ | (409.5 | ) | $ | 1,193.9 | $ | 784.4 | |||||||
| Unrealized (gains) losses on derivative contracts | (368.2 | ) | (6.2 | ) | (374.4 | ) | — | (374.4 | ) | ||||||||||
| Net (gain) loss from asset sales | 148.6 | — | 148.6 | (1,793.4 | ) | (1,644.8 | ) | ||||||||||||
| Interest and other income | (11.8 | ) | (1.0 | ) | (12.8 | ) | (0.3 | ) | (13.1 | ) | |||||||||
| Income tax provision (benefit) | (246.9 | ) | 14.4 | (232.5 | ) | 708.2 | 475.7 | ||||||||||||
| Interest expense (income)(3) | 210.3 | (41.2 | ) | 169.1 | 2.3 | 171.4 | |||||||||||||
| Loss on early extinguishment of debt | — | 2.0 | 2.0 | 2.4 | 4.4 | ||||||||||||||
| Depreciation, depletion and amortization(4) | 984.4 | 10.3 | 994.7 | 31.3 | 1,026.0 | ||||||||||||||
| Impairment | 1,143.2 | — | 1,143.2 | — | 1,143.2 | ||||||||||||||
| Exploration expenses | 9.9 | — | 9.9 | — | 9.9 | ||||||||||||||
| Adjusted EBITDA | $ | 1,437.0 | $ | 1.3 | $ | 1,438.3 | $ | 144.4 | $ | 1,582.7 | |||||||||
| (1) Includes intercompany eliminations. | |||||||||||||||||||
| (2) The pension curtailment is a non-cash expense incurred during the year ended December 31, 2015, due to changes in the Company's pension plan. The Company believes that the pension curtailment loss does not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the loss from the calculation of QEP's Adjusted EBITDA. | |||||||||||||||||||
| (3) Excludes noncontrolling interest's share of $1.5 million during the year ended December 31, 2014, of interest expense attributable to QEP Midstream. | |||||||||||||||||||
| (4) Excludes noncontrolling interests' share of $14.6 million during the year ended December 31, 2014, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C. and QEP Midstream. | |||||||||||||||||||
Adjusted Net Income
This release also contains references to the non-GAAP measure of Adjusted Net Income. Management defines Adjusted Net Income as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, costs from early extinguishment of debt, asset impairments and certain other non-cash and/or non-recurring items. Management believes Adjusted Net Income is an important measure of the Company’s operational performance relative to other gas and oil producing companies.
The following table reconciles net income to Adjusted Net Income:
| Three Months Ended | Year Ended | ||||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||
| (in millions, except earnings per share) | |||||||||||||||
| Net income (loss) | $ | (38.6 | ) | $ | 665.9 | $ | (149.4 | ) | $ | 784.4 | |||||
| Adjustments to net income | |||||||||||||||
| Net (gain) loss from asset sales from continuing operations | 2.3 | (61.7 | ) | (4.6 | ) | 148.6 | |||||||||
| Income taxes on net (gain) loss from asset sales from continuing operations | (0.8 | ) | 21.9 | 1.8 | (53.8 | ) | |||||||||
| Net (gain) loss from asset sales from discontinued operations | — | (1,793.5 | ) | — | (1,793.4 | ) | |||||||||
| Income taxes on net (gain) loss from asset sales from discontinued operations | — | 667.2 | — | 660.0 | |||||||||||
| Unrealized (gains) losses on derivative contracts from continuing operations | 35.7 | (308.5 | ) | 183.7 | (374.4 | ) | |||||||||
| Income taxes on unrealized (gains) losses on derivative contracts from continuing operations | (13.1 | ) | 109.5 | (70.7 | ) | 135.5 | |||||||||
| Pension curtailment loss | — | — | 11.2 | — | |||||||||||
| Income taxes on pension curtailment loss | — | — | (4.3 | ) | — | ||||||||||
| Loss on early extinguishment of debt from continuing operations | — | 2.0 | — | 2.0 | |||||||||||
| Income taxes on loss from early extinguishment of debt from continuing operations | — | (0.7 | ) | — | (0.7 | ) | |||||||||
| Loss on early extinguishment of debt from discontinued operations | — | 2.4 | — | 2.4 | |||||||||||
| Income taxes on loss from early extinguishment of debt discontinued operations | — | (0.9 | ) | — | (0.9 | ) | |||||||||
| Impairment charges from continuing operations | 20.1 | 1,139.6 | 55.6 | 1,143.2 | |||||||||||
| Income taxes impairment charges from continuing operations | (7.4 | ) | (404.6 | ) | (21.4 | ) | (413.8 | ) | |||||||
| Total after-tax adjustments to net income | 36.8 | (627.3 | ) | 151.3 | (545.3 | ) | |||||||||
| Adjusted net income (loss) | $ | (1.8 | ) | $ | 38.6 | $ | 1.9 | $ | 239.1 | ||||||
| Earnings (Loss) per Common Share | |||||||||||||||
| Diluted earnings per share | $ | (0.22 | ) | $ | 3.72 | $ | (0.85 | ) | $ | 4.36 | |||||
| Diluted after-tax adjustments to net income per share | 0.21 | (3.50 | ) | 0.86 | (3.03 | ) | |||||||||
| Diluted Adjusted Net Income per share | $ | (0.01 | ) | $ | 0.22 | $ | 0.01 | $ | 1.33 | ||||||
| Weighted-average common shares outstanding | |||||||||||||||
| Diluted | 176.7 | 179.0 | 176.6 | 179.8 | |||||||||||
The following table presents open derivative positions as of February 19, 2016:
| QEP Energy Commodity Derivative Swap Positions | ||||||||||
| Year | Index | Total Volumes | Average Swap Price per Unit | |||||||
| (in millions) | ||||||||||
| Gas sales | (MMBtu) | |||||||||
| 2016 | NYMEX HH | 46.5 | $ | 2.80 | ||||||
| 2016 | IFNPCR | 61.2 | $ | 2.53 | ||||||
| 2017 | NYMEX HH | 65.7 | $ | 2.76 | ||||||
| 2017 | IFNPCR | 25.6 | $ | 2.53 | ||||||
| 2018 | NYMEX HH | 7.3 | $ | 2.80 | ||||||
| Oil sales | (Bbls) | |||||||||
| 2016 | NYMEX WTI | 6.7 | $ | 55.84 | ||||||
| 2017 | NYMEX WTI | 2.6 | $ | 54.39 | ||||||
| QEP Energy Gas Collars | |||||||||||
| Total Volume | Average Price | Average Price | |||||||||
| Year | Index | Floor | Ceiling | ||||||||
| (in millions) | |||||||||||
| (MMBtu) | ($/MMBtu) | ($/MMBtu) | |||||||||
| 2016 | NYMEX HH | 6.1 | 2.75 | 3.89 | |||||||
| QEP Energy Gas Sales Basis Swaps | ||||||||||
| Year | Index Less Differential | Index | Total Volumes MMBtu | Weighted-Average Differential | ||||||
| (in millions) | ||||||||||
| Gas basis swaps | (MMBtu) | ($/MMBtu) | ||||||||
| 2016 | NYMEX HH | IFNPCR | 30.6 | (0.16 | ) | |||||
| 2017 | NYMEX HH | IFNPCR | 32.9 | (0.19 | ) | |||||
| QEP Marketing Commodity Derivative Positions | |||||||||||
| Year | Type of Contract | Index | Total Volumes | Average Swap Price per MMBtu | |||||||
| (in millions) | |||||||||||
| Gas sales | (MMBtu) | ||||||||||
| 2016 | SWAP | IFNPCR | 3.2 | $ | 2.68 | ||||||
| 2017 | SWAP | IFNPCR | 0.1 | $ | 2.71 | ||||||
| Gas purchases | (MMBtu) | ||||||||||
| 2016 | SWAP | IFNPCR | 0.2 | $ | 1.83 | ||||||