ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
The following information updates the discussion of QEP's financial condition provided in its Annual Report on Form 10-K for the year ended
December 31, 2017
(
2017
Form 10-K) and analyzes the changes in the results of operations between the
three and six months ended
June 30, 2018
and
2017
. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the
2017
Form 10-K.
OVERVIEW
QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas and Louisiana) and the Northern Region (primarily in North Dakota and Utah). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".
In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives), including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As a part of this process, the Company engaged advisors to assist with the divestitures of its Williston Basin and Uinta Basin assets and provided data for potential buyers to evaluate. We continue to engage in discussions with several potential buyers regarding the sale of all or a portion of our Williston assets. As a part of the Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits including severance and accelerated vesting of share-based compensation. Refer to
Note 3 – Acquisitions and Divestitures
and
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for additional information.
On July 5, 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement to sell natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for proceeds of
$155.0 million
, subject to customary purchase price adjustments (the Uinta Basin Divestiture). The transaction is expected to close in September 2018. Since the transaction was substantially finalized at
June 30, 2018
, the assets and liabilities associated with the Uinta Basin Divestiture have been classified as noncurrent assets and liabilities held for sale on the Condensed Consolidated Balance Sheets and the notes accompanying the Condensed Consolidated Financial Statements. Pursuant to signing a purchase and sale agreement for the Uinta Basin Divestiture, QEP recorded
$402.8 million
of proved and unproved properties impairment during the
six months ended
June 30, 2018
. In addition, QEP recorded
$1.9 million
of estimated restructuring costs related to this divestiture during the
six months ended
June 30, 2018
included in the "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. Refer to
Note 1 – Basis of Presentation
,
Note 3 – Acquisitions and Divestitures
and
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information.
Since the beginning of 2014, the Company has made approximately
$2.5 billion
of acquisitions of properties in the Permian Basin and spent approximately
40%
of its capital expenditures (excluding property acquisitions) on its properties in the Permian Basin. In
2018
, the Company plans to spend approximately
70%
of total planned capital expenditures to develop the Permian Basin.
Outlook
The Company continues to focus on reducing its operating costs and per well drilling costs and managing its liquidity as it executes on its plan to transition from a natural gas weighted company to a pure play Permian Basin company. We believe our balance sheet and sufficient liquidity will allow us to grow oil and condensate production in the Permian Basin and achieve our Strategic Initiatives.
Based on current commodity prices, we expect to be able to fund our planned capital program for the remainder of 2018 with cash flow from operating activities and borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for
2018
are expected to be approximately
$1,120.0 million
, a
decrease
of approximately
8%
from 2017 capital expenditures. We continuously evaluate our level of drilling and completion activity in light of drilling results, commodity prices and changes in our operating and development costs and may adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.
Acquisitions and Divestitures
While we believe our extensive inventory of identified drilling locations provides a solid base for growth in production and reserves, the Company continues to evaluate and acquire properties in the Permian Basin to add additional development opportunities and facilitate the drilling of long lateral wells.
Acquisitions
During the
six months ended
June 30, 2018
, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of
$45.1 million
, subject to customary purchase price adjustments. Of the
$45.1 million
,
$37.5 million
was related to acquisitions from various persons who owned additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.
In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) for an aggregate purchase price of
$720.7 million
, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition consists of approximately
15,100
acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the sale of QEP's Pinedale assets.
During the
six months ended
June 30, 2017
, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of
$76.6 million
. In conjunction with these acquisitions, the Company recorded
$5.3 million
of goodwill, which was subsequently impaired in 2017.
Divestitures
During the
six months ended
June 30, 2018
, QEP recorded a pre-tax
loss
of
$1.9 million
related to estimated restructuring costs associated with the Uinta Basin Divestiture (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information), partially offset by a pre-tax
gain
of
$0.7 million
related to the divestiture of properties outside our main operating areas in the Uinta Basin, Pinedale and Other Northern area, and the sale of an underground gas storage facility, in which QEP received aggregate net cash proceeds of
$48.8 million
. In addition, QEP recorded a pre-tax
gain
of
$0.8 million
related to the sale of QEP's assets in Pinedale (the Pinedale Divestiture).
In September 2017, QEP closed on the Pinedale Divestiture for net cash proceeds (after purchase price adjustments) of
$718.2 million
. For the
six months ended
June 30, 2018
, QEP recorded a pre-tax
gain
on sale of
$0.8 million
, due to post-closing purchase price adjustments, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. During the year ended
December 31, 2017
, QEP recorded a pre-tax
gain
on sale of
$180.4 million
, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. In connection with the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed
$45.0 million
. As of
June 30, 2018
, the remaining liability associated with estimated future payments for this commitment was
$23.8 million
.
Financial and Operating Highlights
During the
three months ended
June 30, 2018
, QEP:
|
|
|
|
•
|
Delivered record oil and condensate production of
6.6
MMbbls, a
35%
increase
over
2017
volumes;
|
|
|
|
|
•
|
Increased oil and condensate production by
121%
to a record
3.2
MMbbls in the Permian Basin;
|
|
|
|
|
•
|
Increased gas production in Haynesville/Cotton Valley to
28.5
Bcf, a
71%
increase
over
2017
volumes, primarily due to successful refracturing and drilling programs;
|
|
|
|
|
•
|
Reported net realized oil prices of
$54.30
per bbl, a
16%
increase
over
2017
;
|
|
|
|
|
•
|
Repurchased and retired
0.6 million
shares of the Company's outstanding shares of common stock for
$5.6 million
;
|
|
|
|
|
•
|
Generated a net
loss
of
$336.0 million
or
$1.42
per diluted share; and
|
|
|
|
|
•
|
Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of
$282.6 million
, a
59%
increase
over
2017
.
|
During the
six months ended
June 30, 2018
, QEP:
|
|
|
|
•
|
Delivered oil and condensate production of
11.5
MMbbls, a
21%
increase
over
2017
volumes;
|
|
|
|
|
•
|
Increased oil and condensate production by
119%
to a record
5.4
MMbbls in the Permian Basin;
|
|
|
|
|
•
|
Increased gas production in Haynesville/Cotton Valley to
54.2
Bcf, an
88%
increase
over
2017
volumes, primarily due to successful refracturing and drilling programs;
|
|
|
|
|
•
|
Reported net realized oil prices of
$53.11
per bbl, a
13%
increase
over
2017
;
|
|
|
|
|
•
|
Repurchased and retired
6.2 million
shares of the Company's outstanding shares of common stock for
$58.4 million
;
|
|
|
|
|
•
|
Generated a net
loss
of
$389.6 million
, or
$1.63
per diluted share; and
|
|
|
|
|
•
|
Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of
$454.5 million
, a
31%
increase
over
2017
.
|
Factors Affecting Results of Operations
Supply, Demand, Market Risk and their Impact on Oil and Gas Prices
Oil and gas prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recent years, oil and gas prices have been affected by supply growth, particularly in U.S. oil and gas production, driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.
Changes in the market prices for oil, gas and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, our proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically, field-level prices received for QEP's oil and gas production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $110.62 per barrel in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil, gas or NGL decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil and gas reserves may be materially and adversely affected.
Global Geopolitical and Macroeconomic Factors
QEP continues to monitor the global economy, including Europe and China's economic outlook; the Organization of Petroleum Exporting Countries (OPEC) countries oil production and policies regarding production quotas; political unrest and economic issues in South America, Asia, Europe, the Middle East, and Africa; slowing growth in certain emerging market economies; actions taken by the United States Congress and the president of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; tariffs on goods we use in our operations or on the products we sell; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on oil, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs and could materially impact the Company's financial position, results of operations and cash flow from operations. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices.
Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on maintaining a sufficient liquidity position to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. At
June 30, 2018
, QEP forecasted its
2018
annual production to be approximately
51.1
MMboe and had approximately
66%
of its forecasted oil production and
69%
of its forecasted gas production covered with fixed-price swaps and collars. See Part 1, Item 3 – "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP's commodity derivatives transactions.
Potential for Future Asset Impairments
The carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development and operating costs and expenses and, therefore, are at risk of impairment. The Company uses a cash flow model to assess its proved properties for impairment. The cash flow model includes numerous assumptions, including estimates of future oil, gas and NGL production, estimates of future prices for production that are based on the price forecast that management uses to make investment decisions, including estimates of basis differentials, future operating costs, transportation expenses, production taxes, and development costs that management believes are consistent with its price forecast, and discount rates. Management also considers a number of other factors, including the forward curve for future oil and gas prices, and developments in regional transportation infrastructure when developing its estimate of future prices for production. All inputs for the cash flow model are evaluated at each date of estimate.
We base our fair value estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs.
If forward oil and gas prices decline significantly from
June 30, 2018
levels or we experience negative changes in estimated reserve quantities or we enter into purchase and sale agreements for less than net book value, we have proved and unproved property with a net book value of approximately
$2.7 billion
at risk for impairment, associated with the Williston Basin and proved and unproved property and gathering assets with a net book value of approximately
$718 million
at risk for impairment, associated with Haynesville/Cotton Valley as of
June 30, 2018
. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, entering into purchase and sale agreements for less than net book value of the assets, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.
Multi-Well Pad Drilling and Completion
To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin QEP utilizes "tank-style" development, in which we simultaneously develop multiple subsurface targets by drilling and completing all wells in a given "tank" before any individual well is turned to production. In certain of our producing areas, wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed reserves.
Uncertainties Related to Claims
QEP is currently subject to claims that could adversely impact QEP's liquidity, operating results and/or capital expenditures for a particular reporting period, including, but not limited to those described in
Note 10 – Commitments and Contingencies
, in Item 1 of Part I of this Quarterly Report on Form 10-Q. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes.
Critical Accounting Estimates
QEP's significant accounting policies are described in Item 7 of Part II of its
2017
Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, capitalized exploratory well costs, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, derivative contracts, pension and other postretirement benefits, share-based compensation, income taxes and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.
Drilling, Completion and Production Activities
The following table presents operated and non-operated wells in the process of being drilled or waiting on completion at
June 30, 2018
:
|
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|
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|
|
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|
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
Non-operated
|
|
|
Drilling
|
|
Drilling
|
|
Waiting on completion
|
|
Drilling
|
|
Waiting on completion
|
|
|
Rigs
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
9
|
|
|
0.1
|
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
(1)
|
5
|
|
|
25
|
|
|
24.8
|
|
|
27
|
|
|
26.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1.0
|
|
|
3
|
|
|
0.2
|
|
|
7
|
|
|
0.3
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
____________________________
|
|
|
|
(1)
|
The gross operated drilling well count in the Permian Basin includes 13 wells for which surface casing has been set, but as of
June 30, 2018
, did not have a rig drilling.
|
Each gross well completed in more than one producing zone is counted as a single well. Delays and well shut-ins resulting from multi-well pad drilling have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells could impact planned conversion of PUD reserves to proved developed reserves. QEP had
28
gross operated wells waiting on completion as of
June 30, 2018
.
The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the
three and six months ended
June 30, 2018
:
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|
|
|
|
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|
|
Operated Put on Production
|
|
Non-operated Put on Production
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30, 2018
|
|
June 30, 2018
|
|
June 30, 2018
|
|
June 30, 2018
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
11
|
|
|
10.1
|
|
|
11
|
|
|
10.1
|
|
|
2
|
|
|
0.1
|
|
|
2
|
|
|
0.1
|
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
37
|
|
|
36.1
|
|
|
68
|
|
|
67.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Haynesville/Cotton Valley
|
1
|
|
|
1.0
|
|
|
3
|
|
|
3.0
|
|
|
3
|
|
|
0.1
|
|
|
9
|
|
|
0.5
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
The following table presents the number of operated wells in the process of being drilled or waiting on completion at
June 30, 2018
and operated wells completed and turned to sales (put on production) for the
six months ended
June 30, 2018
:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
68
|
|
|
67.1
|
|
|
11
|
|
|
10.1
|
|
|
3
|
|
|
3.0
|
|
|
2
|
|
|
2.0
|
|
RESULTS OF OPERATIONS
Net Income
QEP generated a net
loss
during the
second quarter
of
2018
of
$336.0 million
, or
$1.42
per diluted share, compared to net
income
of
$45.4 million
, or
$0.19
per diluted share, in the
second quarter
of
2017
. QEP's net
loss
was primarily due to a
$403.7 million
increase
in impairment expense and a $
185.8 million
increase
in unrealized and realized derivative
losses
. These increases to the net
loss
were partially offset by a
$192.5 million
increase
in oil and condensate sales due to a
35%
increase
in oil and condensate production and a
16%
increase
in average net realized oil prices in the
second quarter
of
2018
compared to the
second quarter
of
2017
.
QEP generated a net
loss
during the
first half
of
2018
of
$389.6 million
or
$1.63
per diluted share, compared to net
income
of
$122.3 million
or
$0.51
per diluted share, in the
first half
of
2017
. QEP's net
loss
was primarily due to a
$404.3 million
increase
in impairment expense and a
$399.9 million
increase
in unrealized and realized derivative
losses
. These increases to the net
loss
were partially offset by a
$271.5 million
increase
in oil and condensate sales due to a
21%
increase in oil and condensate production and a
13%
increase in average net realized oil prices in the
first half
of
2018
compared to the
first half
of
2017
.
Adjusted EBITDA (Non-GAAP)
Management defines Adjusted EBITDA (a non-GAAP measure) 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 June 30,
|
|
Six Months Ended 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 EBITDA
increase
d to
$282.6 million
in the
second quarter
of
2018
from
$177.2 million
in the
second quarter
of
2017
, primarily due to a
35%
increase
in oil and condensate production, mainly in the Permian Basin, a
16%
increase
in average net realized oil prices and a
71%
increase
in gas production in Haynesville/Cotton Valley. These changes were partially offset by a
$51.9 million
increase
in realized derivative
losses
, a
$36.4 million
decrease
in gas sales primarily due to the Pinedale divestiture, and a
4%
reduction in average net realized gas prices in the
second quarter
of
2018
compared to the
second quarter
of
2017
.
Adjusted EBITDA
increase
d to
$454.5 million
in the
first half
of
2018
from
$347.9 million
in the
first half
of
2017
, primarily from a
21%
increase in oil and condensate production, mainly in the Permian Basin, a
13%
increase in average net realized oil prices and an
88%
increase
in gas production in Haynesville/Cotton Valley. These increases in the
first half
of
2018
compared to the
first half
of
2017
were partially offset by a
$78.7 million
increase
in realized derivative
losses
and a
$68.9 million
decrease
in gas sales, primarily due to the Pinedale Divestiture.
Revenue
The following table presents our revenues disaggregated by revenue source.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Oil and condensate sales
|
$
|
408.5
|
|
|
$
|
216.0
|
|
|
$
|
192.5
|
|
|
$
|
709.2
|
|
|
$
|
437.7
|
|
|
$
|
271.5
|
|
|
Gas sales
|
97.8
|
|
|
134.2
|
|
|
(36.4
|
)
|
|
199.8
|
|
|
268.7
|
|
|
(68.9
|
)
|
|
NGL sales
|
26.4
|
|
|
22.8
|
|
|
3.6
|
|
|
46.2
|
|
|
51.8
|
|
|
(5.6
|
)
|
|
Oil and condensate, gas and NGL sales, as adjusted
(2)
|
532.7
|
|
|
373.0
|
|
|
$
|
159.7
|
|
|
955.2
|
|
|
758.2
|
|
|
197.0
|
|
|
Transportation and processing costs included in revenue
(3)
|
(12.4
|
)
|
|
—
|
|
|
(12.4
|
)
|
|
(25.1
|
)
|
|
—
|
|
|
(25.1
|
)
|
|
Oil and condensate, gas and NGL sales, as presented
|
$
|
520.3
|
|
|
$
|
373.0
|
|
|
$
|
147.3
|
|
|
$
|
930.1
|
|
|
$
|
758.2
|
|
|
$
|
171.9
|
|
____________________________
|
|
|
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule, refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
|
|
|
(2)
|
Above is a reconciliation of Oil and condensate, gas and NGL sales (a GAAP measure) as presented on the Condensed Consolidated Statements of Operations to Oil and condensate, gas and NGL sales, as adjusted. Oil and condensate, gas and NGL sales, as adjusted excludes transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. Management removes these costs from "Oil and condensate, gas and NGL sales" included on the Condensed Consolidated Statements of Operations to reflect total revenue associated with its production prior to deducting any expenses. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total revenue generated from its wells for the period and is a more comparable measure to reported revenue of its peers. 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. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
|
|
|
(3)
|
Transportation and processing costs in the table above is not representative of total transportation and processing costs incurred. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.
|
Revenue, Volume and Price Variance Analysis
The following table shows volume and price related changes for each of QEP's adjusted production-related revenue categories for the
three and six months ended
June 30, 2018
, compared to the
three and six months ended
June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate
|
|
Gas
|
|
NGL
|
|
Total
|
|
|
(in millions)
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2017
|
$
|
216.0
|
|
|
$
|
134.2
|
|
|
$
|
22.8
|
|
|
$
|
373.0
|
|
|
Changes associated with volumes
(1)
|
75.3
|
|
|
(21.9
|
)
|
|
(3.4
|
)
|
|
50.0
|
|
|
Changes associated with prices
(2)
|
117.2
|
|
|
(14.5
|
)
|
|
7.0
|
|
|
109.7
|
|
|
Three months ended June 30, 2018
|
$
|
408.5
|
|
|
$
|
97.8
|
|
|
$
|
26.4
|
|
|
$
|
532.7
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2017
|
$
|
437.7
|
|
|
$
|
268.7
|
|
|
$
|
51.8
|
|
|
$
|
758.2
|
|
|
Changes associated with volumes
(1)
|
91.1
|
|
|
(44.8
|
)
|
|
(12.5
|
)
|
|
33.8
|
|
|
Changes associated with prices
(2)
|
180.4
|
|
|
(24.1
|
)
|
|
6.9
|
|
|
163.2
|
|
|
Six months ended June 30, 2018
|
$
|
709.2
|
|
|
$
|
199.8
|
|
|
$
|
46.2
|
|
|
$
|
955.2
|
|
____________________________
|
|
|
|
(1)
|
The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the
three and six months ended
June 30, 2018
, as compared to the
three and six months ended
June 30, 2017
, by the average field-level price for the
three and six months ended
June 30, 2017
.
|
|
|
|
|
(2)
|
The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the
three and six months ended
June 30, 2018
, as compared to the
three and six months ended
June 30, 2017
, by the respective volumes for the
three and six months ended
June 30, 2018
. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.
|
Production and Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
Total production volumes (Mboe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
4,459.7
|
|
|
4,573.9
|
|
|
(114.2
|
)
|
|
8,189.4
|
|
|
9,407.9
|
|
|
(1,218.5
|
)
|
|
Pinedale
|
—
|
|
|
3,316.7
|
|
|
(3,316.7
|
)
|
|
0.1
|
|
|
6,831.6
|
|
|
(6,831.5
|
)
|
|
Uinta Basin
|
821.7
|
|
|
897.0
|
|
|
(75.3
|
)
|
|
1,626.2
|
|
|
1,865.3
|
|
|
(239.1
|
)
|
|
Other Northern
|
42.8
|
|
|
337.1
|
|
|
(294.3
|
)
|
|
148.2
|
|
|
667.5
|
|
|
(519.3
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
4,016.2
|
|
|
1,932.1
|
|
|
2,084.1
|
|
|
6,799.1
|
|
|
3,321.6
|
|
|
3,477.5
|
|
|
Haynesville/Cotton Valley
|
4,761.3
|
|
|
2,792.3
|
|
|
1,969.0
|
|
|
9,051.8
|
|
|
4,839.0
|
|
|
4,212.8
|
|
|
Other Southern
|
4.4
|
|
|
11.5
|
|
|
(7.1
|
)
|
|
15.9
|
|
|
18.0
|
|
|
(2.1
|
)
|
|
Total production
|
14,106.1
|
|
|
13,860.6
|
|
|
245.5
|
|
|
25,830.7
|
|
|
26,950.9
|
|
|
(1,120.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equivalent prices (per Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level equivalent price
|
$
|
37.77
|
|
|
$
|
26.91
|
|
|
$
|
10.86
|
|
|
$
|
36.98
|
|
|
$
|
28.13
|
|
|
$
|
8.85
|
|
|
Commodity derivative impact
|
(3.23
|
)
|
|
0.46
|
|
|
(3.69
|
)
|
|
(3.45
|
)
|
|
(0.36
|
)
|
|
(3.09
|
)
|
|
Net realized equivalent price
|
$
|
34.54
|
|
|
$
|
27.37
|
|
|
$
|
7.17
|
|
|
$
|
33.53
|
|
|
$
|
27.77
|
|
|
$
|
5.76
|
|
Oil and Condensate Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
Oil and condensate production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
3,166.8
|
|
|
3,076.5
|
|
|
90.3
|
|
|
5,779.0
|
|
|
6,413.2
|
|
|
(634.2
|
)
|
|
Pinedale
|
—
|
|
|
137.7
|
|
|
(137.7
|
)
|
|
—
|
|
|
280.7
|
|
|
(280.7
|
)
|
|
Uinta Basin
|
168.6
|
|
|
162.5
|
|
|
6.1
|
|
|
320.3
|
|
|
328.6
|
|
|
(8.3
|
)
|
|
Other Northern
|
19.2
|
|
|
37.3
|
|
|
(18.1
|
)
|
|
57.0
|
|
|
64.2
|
|
|
(7.2
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
3,207.2
|
|
|
1,449.6
|
|
|
1,757.6
|
|
|
5,366.3
|
|
|
2,451.3
|
|
|
2,915.0
|
|
|
Haynesville/Cotton Valley
|
4.5
|
|
|
5.7
|
|
|
(1.2
|
)
|
|
10.3
|
|
|
12.9
|
|
|
(2.6
|
)
|
|
Other Southern
|
1.3
|
|
|
1.0
|
|
|
0.3
|
|
|
8.7
|
|
|
2.1
|
|
|
6.6
|
|
|
Total production
|
6,567.6
|
|
|
4,870.3
|
|
|
1,697.3
|
|
|
11,541.6
|
|
|
9,553.0
|
|
|
1,988.6
|
|
|
Average field-level oil prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
64.99
|
|
|
$
|
43.86
|
|
|
$
|
21.13
|
|
|
$
|
63.14
|
|
|
$
|
45.27
|
|
|
$
|
17.87
|
|
|
Southern Region
|
$
|
59.30
|
|
|
$
|
45.49
|
|
|
$
|
13.81
|
|
|
$
|
59.51
|
|
|
$
|
47.39
|
|
|
$
|
12.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
62.21
|
|
|
$
|
44.35
|
|
|
$
|
17.86
|
|
|
$
|
61.45
|
|
|
$
|
45.82
|
|
|
$
|
15.63
|
|
|
Commodity derivative impact
|
(7.91
|
)
|
|
2.37
|
|
|
(10.28
|
)
|
|
(8.34
|
)
|
|
0.99
|
|
|
(9.33
|
)
|
|
Net realized price
|
$
|
54.30
|
|
|
$
|
46.72
|
|
|
$
|
7.58
|
|
|
$
|
53.11
|
|
|
$
|
46.81
|
|
|
$
|
6.30
|
|
Oil and condensate revenues
increase
d
$192.5 million
, or
89%
, in the
second quarter
of
2018
compared to the
second quarter
of
2017
, due to
higher
average field-level prices and
higher
oil and condensate production volumes. Average field-level oil prices
increase
d
40%
in the
second quarter
of
2018
compared to the
second quarter
of
2017
primarily driven by an
increase
in average NYMEX-WTI oil prices for the comparable periods. The
35%
increase
in production volumes was driven by increases in the Permian Basin due to increased drilling activity, partially offset by a loss of volumes from Pinedale as a result of the Pinedale Divestiture.
Oil a
nd condensate
revenues
increase
d
$271.5 million
, or
62%
, in the
first half
of
2018
compared to the
first half
of
2017
, due to
higher
average field-level prices and
higher
oil and condensate production volumes. Average field-level oil prices
increase
d
34%
in the
first half
of
2018
compared to the
first half
of
2017
primarily driven by an
increase
in average NYMEX-WTI oil prices for the comparable periods. The
21%
increase
in production volumes was driven by an increase in the Permian Basin due to increased drilling activity, partially offset by decrease in production in the Williston Basin and a loss of volumes from Pinedale as a result of the Pinedale Divestiture.
Gas Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
Gas production volumes (Bcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
3.8
|
|
|
4.1
|
|
|
(0.3
|
)
|
|
7.2
|
|
|
8.1
|
|
|
(0.9
|
)
|
|
Pinedale
|
—
|
|
|
17.6
|
|
|
(17.6
|
)
|
|
—
|
|
|
36.1
|
|
|
(36.1
|
)
|
|
Uinta Basin
|
3.7
|
|
|
4.2
|
|
|
(0.5
|
)
|
|
7.4
|
|
|
8.8
|
|
|
(1.4
|
)
|
|
Other Northern
|
0.1
|
|
|
1.8
|
|
|
(1.7
|
)
|
|
0.5
|
|
|
3.6
|
|
|
(3.1
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
2.1
|
|
|
1.3
|
|
|
0.8
|
|
|
4.0
|
|
|
2.5
|
|
|
1.5
|
|
|
Haynesville/Cotton Valley
|
28.5
|
|
|
16.7
|
|
|
11.8
|
|
|
54.2
|
|
|
28.9
|
|
|
25.3
|
|
|
Other Southern
|
0.1
|
|
|
0.1
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
—
|
|
|
Total production
|
38.3
|
|
|
45.8
|
|
|
(7.5
|
)
|
|
73.4
|
|
|
88.1
|
|
|
(14.7
|
)
|
|
Average field-level gas prices (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
2.17
|
|
|
$
|
2.86
|
|
|
$
|
(0.69
|
)
|
|
$
|
2.48
|
|
|
$
|
3.05
|
|
|
$
|
(0.57
|
)
|
|
Southern Region
|
$
|
2.65
|
|
|
$
|
3.03
|
|
|
$
|
(0.38
|
)
|
|
$
|
2.78
|
|
|
$
|
3.05
|
|
|
$
|
(0.27
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
2.55
|
|
|
$
|
2.93
|
|
|
$
|
(0.38
|
)
|
|
$
|
2.72
|
|
|
$
|
3.05
|
|
|
$
|
(0.33
|
)
|
|
Commodity derivative impact
|
0.17
|
|
|
(0.11
|
)
|
|
0.28
|
|
|
0.10
|
|
|
(0.22
|
)
|
|
0.32
|
|
|
Net realized price
|
$
|
2.72
|
|
|
$
|
2.82
|
|
|
$
|
(0.10
|
)
|
|
$
|
2.82
|
|
|
$
|
2.83
|
|
|
$
|
(0.01
|
)
|
Gas revenues
decrease
d
$36.4 million
, or
27%
, in the
second quarter
of
2018
compared to the
second quarter
of
2017
, due to
lower
gas production volumes and
lower
average field-level prices. Production volumes decreased primarily due to the Pinedale Divestiture and divestitures in the Other Northern area. These production decreases were partially offset by an increase in production in the
second quarter
of
2018
in Haynesville/Cotton Valley. The 71% increase in gas production in Haynesville/Cotton Valley was due to the continued refracturing and drilling programs. Average field-level gas prices
decrease
d
13%
in the
second quarter
of
2018
compared to the
second quarter
of
2017
, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.
Gas revenues
decrease
d
$68.9 million
, or
26%
, in the
first half
of
2018
compared to the
first half
of
2017
, due to
lower
gas production volumes and
lower
average field-level prices. Production volumes decreased primarily due to the Pinedale Divestiture, divestitures in the Other Northern area and decreases in the Uinta Basin due to normal decline, partially offset by two new well completions in the Uinta Basin late in the first quarter of 2018. These production decreases were partially offset by an 87% increase in gas production in the
first half
of
2018
in Haynesville/Cotton Valley. The increase in gas production in Haynesville/Cotton Valley was due to the continued refracturing and drilling programs. Average field-level gas prices
decrease
d
11%
in the
first half
of
2018
compared to the
first half
of
2017
, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.
NGL Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
NGL production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
666.7
|
|
|
822.7
|
|
|
(156.0
|
)
|
|
1,218.1
|
|
|
1,645.9
|
|
|
(427.8
|
)
|
|
Pinedale
|
—
|
|
|
231.5
|
|
|
(231.5
|
)
|
|
—
|
|
|
524.0
|
|
|
(524.0
|
)
|
|
Uinta Basin
|
34.9
|
|
|
33.6
|
|
|
1.3
|
|
|
71.2
|
|
|
75.0
|
|
|
(3.8
|
)
|
|
Other Northern
|
2.4
|
|
|
3.9
|
|
|
(1.5
|
)
|
|
5.7
|
|
|
8.2
|
|
|
(2.5
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
448.4
|
|
|
259.8
|
|
|
188.6
|
|
|
761.3
|
|
|
447.6
|
|
|
313.7
|
|
|
Haynesville/Cotton Valley
|
0.2
|
|
|
2.7
|
|
|
(2.5
|
)
|
|
0.3
|
|
|
8.7
|
|
|
(8.4
|
)
|
|
Other Southern
|
0.2
|
|
|
0.7
|
|
|
(0.5
|
)
|
|
0.6
|
|
|
0.9
|
|
|
(0.3
|
)
|
|
Total production
|
1,152.8
|
|
|
1,354.9
|
|
|
(202.1
|
)
|
|
2,057.2
|
|
|
2,710.3
|
|
|
(653.1
|
)
|
|
Average field-level NGL prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
23.44
|
|
|
$
|
17.37
|
|
|
$
|
6.07
|
|
|
$
|
23.05
|
|
|
$
|
19.82
|
|
|
$
|
3.23
|
|
|
Southern Region
|
$
|
21.91
|
|
|
$
|
14.77
|
|
|
$
|
7.14
|
|
|
$
|
21.49
|
|
|
$
|
15.62
|
|
|
$
|
5.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
22.84
|
|
|
$
|
16.86
|
|
|
$
|
5.98
|
|
|
$
|
22.47
|
|
|
$
|
19.11
|
|
|
$
|
3.36
|
|
|
Commodity derivative impact
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net realized price
|
$
|
22.84
|
|
|
$
|
16.86
|
|
|
$
|
5.98
|
|
|
$
|
22.47
|
|
|
$
|
19.11
|
|
|
$
|
3.36
|
|
NGL production volumes and revenues represent the sale of liquids derived from the processing of QEP's natural gas production. NGL revenues
increase
d
$3.6 million
, or
16%
, during the
second quarter
of
2018
compared to the
second quarter
of
2017
, due to
higher
average field-level prices, partially offset by
lower
NGL production volumes. The
35%
increase
in NGL prices during the
second quarter
of
2018
compared to the
second quarter
of
2017
, was primarily driven by an increase in propane, ethane and other NGL component prices. The increase in price was partially offset by a
15%
decrease
in NGL production volumes. The decrease was primarily driven by a loss of volumes from Pinedale due to the Pinedale Divestiture and a production decrease in the Williston Basin due to declining gas volumes and a lower amount of ethane allocated to us by the midstream provider in the second quarter of 2018 compared to the second quarter of 2017. These production decreases were partially offset by an increase in production in the Permian Basin due to increased drilling activity.
NGL revenues
decrease
d
$5.6 million
, or
11%
, during the
first half
of
2018
compared to the
first half
of
2017
, due to
lower
NGL production volumes, partially offset by
higher
average field-level prices. The
24%
decrease
in NGL production volumes was primarily driven by a loss of volumes from Pinedale due to the Pinedale Divestiture and production decreases in the Williston Basin due to declining gas volumes and a lower amount of ethane allocated to us by the midstream provider in the first half of 2018 compared to the first half 2017. These decreases were partially offset by an increase in production in the Permian Basin due to increased drilling activity. The overall decrease in production volumes was partially offset by an
18%
increase
in NGL prices during the
first half
of
2018
compared to the
first half
of
2017
, primarily driven by an increase in propane, ethane and other NGL component prices.
Resale Margin and Storage Activity
QEP purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. The following table is a summary of QEP's financial results from its resale activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
|
(in millions)
|
|
Purchased oil and gas sales
|
$
|
9.1
|
|
|
$
|
8.0
|
|
|
$
|
1.1
|
|
|
$
|
23.2
|
|
|
$
|
38.9
|
|
|
$
|
(15.7
|
)
|
|
Purchased oil and gas expense
|
(9.8
|
)
|
|
(9.1
|
)
|
|
(0.7
|
)
|
|
(25.3
|
)
|
|
(38.5
|
)
|
|
13.2
|
|
|
Realized gains (losses) on gas storage derivative contracts
|
0.1
|
|
|
—
|
|
|
0.1
|
|
|
0.3
|
|
|
(0.2
|
)
|
|
0.5
|
|
|
Resale margin
|
$
|
(0.6
|
)
|
|
$
|
(1.1
|
)
|
|
$
|
0.5
|
|
|
$
|
(1.8
|
)
|
|
$
|
0.2
|
|
|
$
|
(2.0
|
)
|
Purchased oil and gas sales and expense
increase
d during the
second quarter
of
2018
compared to
second quarter
of
2017
, due to an increase in resale volumes to meet Northern Region gas transportation commitments retained in the various divestitures partially offset by lower resale volumes needed to meet gas transportation commitments in the Southern Region due to increased production.
Purchased oil and gas sales and expense
decrease
d during the
first half
of
2018
compared to
first half
of
2017
, due to lower resale volumes needed to meet gas transportation commitments in the Southern Region due to increased production.
Operating Expenses
The following table presents QEP production costs and production costs on a per unit of production basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
(3.5
|
)
|
|
$
|
139.0
|
|
|
$
|
139.2
|
|
|
$
|
(0.2
|
)
|
|
Adjusted transportation and processing costs
(1)
|
43.6
|
|
|
72.2
|
|
|
(28.6
|
)
|
|
90.3
|
|
|
142.4
|
|
|
(52.1
|
)
|
|
Production and property taxes
|
37.6
|
|
|
28.5
|
|
|
9.1
|
|
|
66.5
|
|
|
57.6
|
|
|
8.9
|
|
|
Total production costs
|
$
|
147.7
|
|
|
$
|
170.7
|
|
|
$
|
(23.0
|
)
|
|
$
|
295.8
|
|
|
$
|
339.2
|
|
|
$
|
(43.4
|
)
|
|
|
(per Boe)
|
|
Lease operating expense
|
$
|
4.71
|
|
|
$
|
5.05
|
|
|
$
|
(0.34
|
)
|
|
$
|
5.38
|
|
|
$
|
5.17
|
|
|
$
|
0.21
|
|
|
Adjusted transportation and processing costs
(1)
|
3.09
|
|
|
5.21
|
|
|
(2.12
|
)
|
|
3.49
|
|
|
5.28
|
|
|
(1.79
|
)
|
|
Production and property taxes
|
2.66
|
|
|
2.06
|
|
|
0.60
|
|
|
2.57
|
|
|
2.14
|
|
|
0.43
|
|
|
Total production costs
|
$
|
10.46
|
|
|
$
|
12.32
|
|
|
$
|
(1.86
|
)
|
|
$
|
11.44
|
|
|
$
|
12.59
|
|
|
$
|
(1.15
|
)
|
____________________________
|
|
|
|
(1)
|
Below are reconciliations of transportation and processing costs (a GAAP measure) as presented on the Condensed Consolidated Statements of Operations and on a unit of production basis to adjusted transportation and processing costs. Adjusted transportation and processing costs includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. Management adds these costs together with transportation and processing costs reflected on the Condensed Consolidated Statements of Operations to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of 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. 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. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
2018
|
|
2017
(1)
|
|
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
|
)
|
____________________________
|
|
|
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to
Note 2 – Revenue
in Part 1, Item 1 of this Quarterly Report on Form 10-Q.
|
Lease operating expense (LOE).
QEP's LOE
decrease
d
$3.5 million
, or
5%
, in the
second quarter
of
2018
compared to the
second quarter
of
2017
due to the Pinedale Divestiture. Excluding Pinedale, LOE increased $5.0 million, primarily driven by increases in the Permian Basin due to the
2017
Permian Basin Acquisition, and increased maintenance and repairs, power and fuel and chemical expenses.
During the
second quarter
of
2018
, LOE
decrease
d
$0.34
per Boe, or
7%
, compared with the
second quarter
of
2017
, but was down 19% excluding the loss of lower LOE production in Pinedale as a result of the Pinedale Divestiture. The 19% per BOE decrease related to lower cost production from the recent horizontal well completions in the Permian Basin and Haynesville/Cotton Valley.
QEP's LOE
decrease
d
$0.2 million
in the
first half
of
2018
compared to the
first half
of
2017
, due to the Pinedale Divestiture. Excluding Pinedale, LOE increased $17.1 million, primarily driven by increases in the Permian Basin, Williston Basin and Haynesville/Cotton Valley. The Permian Basin increase relates to the 2017 Permian Basin Acquisition, and increased maintenance and repairs, power and fuel and chemical expenses. The Williston Basin increase was due to increased power and fuel, compression and labor costs. The Haynesville/Cotton Valley increase was due to higher labor and water disposal costs.
During the
first half
of
2018
, LOE
increase
d
$0.21
per Boe, or
4%
, compared with the
first half
of
2017
, due to the loss of lower LOE production in Pinedale as a result of the Pinedale Divestiture. Excluding the Pinedale Divestiture, LOE per Boe was down
12%
primarily due to lower cost production from the recent horizontal well completions in the Permian Basin and Haynesville/Cotton Valley partially offset by an increase in our Williston Basin rate due to increased expenses on declining production volumes.
Adjusted transportation and processing costs.
Adjusted transportation and processing costs
decrease
d
$28.6 million
, or
40%
, during the
second quarter
of
2018
compared to the
second quarter
of
2017
. The
decrease
in expense was primarily attributable to the Pinedale Divestiture.
During the
second quarter
of
2018
, adjusted transportation and processing costs
decrease
d
$2.12
per Boe, or
41%
, compared to the
second quarter
of
2017
, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, adjusted transportation and processing costs per Boe were down
28%
due to decreases in both Haynesville/Cotton Valley and the Permian Basin during the
second quarter
of
2018
compared to the
second quarter
of
2017
. The cost per Boe decreased in Haynesville/Cotton Valley due to increased production that increased utilization of the Company's firm transportation commitments on interstate pipelines. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts.
Adjusted transportation and processing costs
decrease
d
$52.1 million
, or
37%
, during the
first half
of
2018
compared to the
first half
of
2017
. The
decrease
in expense was primarily attributable to the Pinedale Divestiture.
During the
first half
of
2018
, adjusted transportation and processing costs
decrease
d
$1.79
per Boe, or
34%
, compared to the
first half
of
2017
, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, adjusted transportation and processing costs per Boe were down 23% due to a decrease in Haynesville/Cotton Valley and the Permian Basin during the
first half
of
2018
compared to the
first half
of
2017
. The cost per Boe decreased in Haynesville/Cotton Valley due to increased production that increased utilization of the Company's firm transportation commitments on interstate pipelines. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts.
General and administrative (G&A) expense.
During the
second quarter
of
2018
, G&A expense
increase
d
$24.5 million
, or
78%
, compared to the
second quarter
of
2017
. During the
second quarter
of
2018
, QEP incurred
$9.5 million
in restructuring costs associated with the implementation of our Strategic Initiatives, of which
$6.3 million
relates to retention expense
,
$1.7 million
of termination benefits,
$1.2 million
of accelerated share-based compensation and
$0.3 million
related to office lease termination costs (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q)
.
In addition to these restructuring related costs, QEP recognized an $11.7 million increase in share-based compensation and changes in the mark-to-market value of the Deferred Compensation Wrap Plan and a $4.5 million increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture.
During the
first half
of
2018
, G&A expense
increase
d
$51.0 million
, or
79%
, compared to the
first half
of
2017
. During the
first half
of
2018
, QEP incurred
$17.4 million
in restructuring costs associated with the implementation of our Strategic Initiatives, of which
$8.0 million
relates to retention expense,
$5.1 million
of termination benefits
$4.0 million
of accelerated share-based compensation and
$0.3 million
related to office lease termination costs (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q)
.
In addition to these restructuring related costs, QEP recognized a $16.7 million increase in share-based compensation and changes in the mark-to-market value of the Deferred Compensation Wrap Plan, a $8.2 million increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture and a $5.0 million increase in legal and outside expenses related to our Strategic Initiatives.
Production and property taxes.
In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production and property taxes
increase
d
$9.1 million
, or
32%
, in the
second quarter
of
2018
compared to the
second quarter
of
2017
, primarily due to increased oil pricing and increased oil and condensate production in the Williston and Permian basins, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.
During the
second quarter
of
2018
, production and property taxes
increase
d
$0.60
per Boe, or
29%
, compared to the
second quarter
of
2017
, but increased 63% excluding the Pinedale Divestiture. The 63% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe.
Production and property taxes
increase
d
$8.9 million
, or
15%
, in the
first half
of
2018
compared to the
first half
of
2017
, primarily due to increased oil pricing and increased oil and condensate production in the Permian Basin, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.
During the
first half
of
2018
, production and property taxes
increase
d
$0.43
per Boe, or
20%
, compared to the
first half
of
2017
, but increased 57% excluding the Pinedale Divestiture. The 57% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins, partially offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe.
Depreciation, depletion and amortization (DD&A).
DD&A expense
increase
d
$50.7 million
in the
second quarter
of
2018
compared to the
second quarter
of
2017
, primarily due to increased production and a higher DD&A rate in the Permian Basin and Haynesville/Cotton Valley, partially offset by lower DD&A due to the Pinedale Divestiture.
DD&A expense
increase
d
$55.4 million
in the
first half
of
2018
compared to the
first half
of
2017
, primarily due to increased production and a higher DD&A rate in the Permian Basin and Haynesville/Cotton Valley, partially offset by lower DD&A due to the Pinedale Divestiture.
Impairment expense.
During the
second quarter
of
2018
, QEP recorded impairment charges of
$403.7 million
, which were primarily due to the impairment of proved and unproved properties related to the Uinta Basin Divestiture.
During the
first half
of
2018
, QEP recorded impairment charges of
$404.4 million
, of which
$402.8 million
of proved and unproved properties impairment was triggered by the Uinta Basin Divestiture and
$1.6 million
was related to expiring leaseholds on unproved properties and impairment of proved properties related to a divestiture in the Other Northern area.
Net gain (loss) from asset sales, inclusive of restructuring costs.
During the
second quarter
of
2018
, QEP recognized a
loss
on the sale of assets of
$3.9 million
, primarily related to a pre-tax
loss
of
$1.9 million
related to estimated restructuring costs associated with the Uinta Basin Divestiture (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). In addition, QEP recognized a pre-tax
loss
of
$2.0 million
related to the divestiture of properties outside our main operating areas in the Uinta Basin and the Other Northern area, and an underground gas storage facility. During the
second quarter
of
2017
, QEP recognized a gain on the sale of assets of
$19.8 million
related to the sale of non-core Other Northern properties.
During the
first half
of
2018
, QEP recognized a
loss
on the sale of assets of
$0.4 million
primarily comprised of
$1.9 million
of estimated restructuring costs associated with the Uinta Basin Divestiture (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information) partially offset by a net pre-tax
gain
on sale of assets of
$1.5 million
related to the divestiture of properties outside our main operating areas in the Uinta Basin, Pinedale and the Other Northern area, and an underground gas storage facility. During the
first half
of
2017
, QEP recognized a gain on the sale of assets of
$19.8 million
related to the sale of non-core Other Northern properties.
Non-operating Expenses
Realized and unrealized gains (losses) on derivative contracts.
Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts, which are marked-to-market each quarter. During the
second quarter
of
2018
,
losses
on commodity derivative contracts were
$79.1 million
, of which
$45.5 million
were realized
losses
and
$33.6 million
were unrealized
losses
. During the
second quarter
of
2017
,
gains
on commodity derivative contracts were
$106.7 million
, of which
$100.3 million
were unrealized
gains
and
$6.4 million
were realized
gains
.
During the
first half
of
2018
,
losses
on commodity derivative contracts were
$132.3 million
of which
$88.7 million
were realized
losses
and
$43.6 million
were unrealized
losses
. During the
first half
of
2017
,
gains
on commodity derivative contracts were
$267.6 million
, of which
$277.6 million
were unrealized
gains
and
$10.0 million
were realized
losses
.
Interest expense.
Interest expense
increase
d
$3.3 million
, or
9%
, during the
second quarter
of
2018
compared to the
second quarter
of
2017
. The
increase
during the
second quarter
of
2018
was primarily related to increased interest on the borrowings under the credit facility partially offset by lower interest rates on senior notes.
Interest expense
increase
d
$4.5 million
, or
7%
, during the
first half
of
2018
compared to the
first half
of
2017
. The
increase
during the
first half
of
2018
was primarily related to increased interest on the borrowings under the credit facility partially offset by lower interest rates on senior notes.
Income tax (provision) benefit.
Income tax
benefit
increase
d
$133.5 million
during the
second quarter
of
2018
compared to the
second quarter
of
2017
. The
increase
in
benefit
was the result of a net
loss
during the
second quarter
of
2018
compared to net
income
during the
second quarter
of
2017
and a lower combined effective federal and state income tax rate of
24.0%
during the
second quarter
of
2018
compared to a rate of
37.6%
during the
second quarter
of
2017
. The
decrease
in income tax rate was primarily the result of the Tax Cuts and Job Act (H.R. 1) signed into law in December 2017.
Income tax
benefit
increase
d
$193.0 million
during the
first half
of
2018
compared to the
first half
of
2017
. The
increase
in
benefit
was the result of a net
loss
during the
first half
of
2018
compared to net
income
during the
first half
of
2017
and a lower combined effective federal and state income tax rate of
23.6%
during the
first half
of
2018
compared to a rate of
37.3%
during the
first half
of
2017
. The
decrease
in income tax rate was primarily the result of the Tax Cuts and Job Act (H.R. 1) signed into law in December 2017.
LIQUIDITY AND CAPITAL RESOURCES
QEP strives to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations, capital expenditures and Strategic Initiatives. The Company utilizes derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility. The Company expects that cash flows from its operating activities and borrowings under its revolving credit facility will be sufficient to fund its operations and capital expenditures during the next 12 months and the foreseeable future.
QEP also periodically accesses debt and equity markets and sells properties. In the first half of 2018, QEP engaged advisors to assist with the divestiture of its Williston Basin and Uinta Basin assets and provided data for potential buyers to evaluate. If the marketing of these assets is successful, the Company plans to use the proceeds to fund on-going operations, reduce debt, repurchase shares and for general corporate purposes.
The Company estimates, that as of
June 30, 2018
, it could incur additional indebtedness of approximately
$675.0 million
and be in compliance with the covenants contained in its revolving credit facility. To the extent actual operating results, realized commodity prices or uses of cash differ from the Company's assumptions, QEP's liquidity could be adversely affected.
Credit Facility
QEP's revolving credit facility, which matures, subject to satisfaction of certain conditions, in September 2022, provides for loan commitments of
$1.25 billion
. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.00 times consolidated EBITDA (as defined in the credit agreement) commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019 through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The Company is currently not subject to the present value coverage ratio. As of
June 30, 2018
and
2017
, QEP was in compliance with the covenants under the credit agreement.
During the
six months ended
June 30, 2018
, QEP's weighted-average interest rate on borrowings from its credit facility was
4.22%
. As of
June 30, 2018
, QEP had
$575.0 million
of borrowings outstanding and
$0.3 million
in letters of credit outstanding under the credit facility. As of
December 31, 2017
, QEP had
$89.0 million
of borrowings outstanding and
$1.0 million
in letters of credit outstanding under the credit facility. As of
July 20, 2018
, QEP had
$525.0 million
of borrowings outstanding, had
$0.3 million
in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.
Senior Notes
The Company's senior notes outstanding as of
June 30, 2018
, totaled
$2,099.3 million
principal amount and are comprised of five issuances as follows:
|
|
|
|
•
|
$51.7 million
6.80% Senior Notes due March 2020;
|
|
|
|
|
•
|
$397.6 million
6.875% Senior Notes due March 2021;
|
|
|
|
|
•
|
$500.0 million
5.375% Senior Notes due October 2022;
|
|
|
|
|
•
|
$650.0 million
5.25% Senior Notes due May 2023; and
|
|
|
|
|
•
|
$500.0 million
5.625% Senior Notes due March 2026.
|
Cash Flow from Operating Activities
Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months.
Net cash provided by (used in) operating activities is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
|
(in millions)
|
|
Net income (loss)
|
$
|
(389.6
|
)
|
|
$
|
122.3
|
|
|
$
|
(511.9
|
)
|
|
Non-cash adjustments to net income (loss)
|
792.2
|
|
|
163.0
|
|
|
629.2
|
|
|
Changes in operating assets and liabilities
|
(25.7
|
)
|
|
10.7
|
|
|
(36.4
|
)
|
|
Net cash provided by (used in) operating activities
|
$
|
376.9
|
|
|
$
|
296.0
|
|
|
$
|
80.9
|
|
Net cash
provided by
operating activities was
$376.9 million
during the
first half
of
2018
, which included
$389.6 million
of net
loss
,
$792.2 million
of non-cash adjustments to the net
loss
and
$25.7 million
in changes in operating assets and liabilities. Non-cash adjustments to the net
loss
of
$792.2 million
primarily included DD&A expense of
$438.7 million
,
$404.4 million
of impairment expense,
$43.6 million
of unrealized
losses
on derivative contracts, and
$23.4 million
of share-based compensation expense, partially offset by
$120.5 million
of deferred income taxes. The
decrease
in changes in operating assets and liabilities of
$25.7 million
primarily resulted from an
increase
in accounts receivable of
$32.6 million
and a
decrease
in other long-term liabilities of
$9.6 million
, partially offset by an
increase
in interest payable of
$6.7 million
and an
increase
in accounts payable and accrued expenses of
$3.2 million
.
Net cash
provided by
operating activities was
$296.0 million
during the
first half
of
2017
, which included
$122.3 million
of net
income
,
$163.0 million
of non-cash adjustments to net
income
and a
$10.7 million
increase
in changes in operating assets and liabilities. Non-cash adjustments to net
income
of
$163.0 million
primarily included DD&A expense of
$383.3 million
and
$67.2 million
of deferred income taxes, partially offset by unrealized gains on derivative contracts of
$277.6 million
. The
increase
in changes in operating assets and liabilities of
$10.7 million
primarily resulted from a
decrease
in accounts receivable of
$27.4 million
, partially offset by a
decrease
in accounts payable and accrued expenses of
$7.8 million
and a decrease in the ARO liability of
$2.0 million
.
Cash Flow from Investing Activities
A comparison of capital expenditures for the
first half
of
2018
and
2017
, are presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
Change
|
|
|
(in millions)
|
|
Property acquisitions
|
$
|
45.1
|
|
|
$
|
76.6
|
|
|
$
|
(31.5
|
)
|
|
Property, plant and equipment capital expenditures
|
784.5
|
|
|
520.3
|
|
|
264.2
|
|
|
Total accrued capital expenditures
|
829.6
|
|
|
596.9
|
|
|
232.7
|
|
|
Change in accruals and other non-cash adjustments
|
(20.2
|
)
|
|
(42.4
|
)
|
|
22.2
|
|
|
Total cash capital expenditures
|
$
|
809.4
|
|
|
$
|
554.5
|
|
|
$
|
254.9
|
|
In the
first half
of
2018
, on an accrual basis, the Company invested
$784.5 million
on property, plant and equipment capital expenditures (which excludes property acquisitions), an
increase
of
$264.2 million
compared to the
first half
of
2017
. In the
first half
of
2018
, QEP's significant capital expenditures included
$498.9 million
in the Permian Basin (including midstream infrastructure of
$38.3 million
, primarily related to fresh water supply, produced water gathering, salt water disposal and oil and gas gathering),
$157.8 million
in the Williston Basin,
$120.6 million
in Haynesville/Cotton Valley (including midstream infrastructure of
$7.5 million
, primarily related to gas gathering) and
$4.5 million
in the Uinta Basin. In addition, in the
first half
of
2018
, QEP acquired various oil and gas properties, primarily proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of
$45.1 million
, of which
$37.5 million
was related to the 2017 Permian Basin Acquisition.
In the
first half
of
2017
, on an accrual basis, the Company invested
$520.3 million
on property, plant and equipment capital expenditures (which excludes property acquisitions), including
$297.7 million
in the Permian Basin,
$128.1 million
in the Williston Basin,
$72.2 million
in Haynesville/Cotton Valley and
$12.3 million
in Pinedale. In addition, during the
first half
of
2017
, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds and additional surface acreage primarily in the Permian Basin, for an aggregate purchase price of
$76.6 million
.
The mid-point of our
2018
forecasted capital expenditures (excluding property acquisitions) is
$1,120.0 million
. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities and borrowings under the credit facility. The aggregate levels of capital expenditures for
2018
and the allocation of those expenditures are dependent on a variety of factors, including drilling results, oil, gas and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management's business assessments as to where QEP's capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.
Cash Flow from Financing Activities
In the
first half
of
2018
, net cash
provided by
financing activities was
$386.4 million
compared to net cash
used in
financing activities of
$8.0 million
in the
first half
of
2017
. During the
first half
of
2018
, QEP had borrowings from the credit facility of
$2,029.5 million
and repayments on its credit facility of
$1,543.5 million
. In addition, QEP used
$58.4 million
of cash to repurchase common stock under the Company's share repurchase program and had treasury stock repurchases of
$5.9 million
related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. QEP had a decrease in checks outstanding in excess of cash balances of
$35.5 million
. During the
first half
of
2017
, QEP had treasury stock repurchases of
$6.4 million
, a decrease in long-term debt issuance costs paid of
$1.1 million
and a decrease in checks outstanding in excess of cash balances of
$0.5 million
.
As of
June 30, 2018
, long-term debt consisted of
$2,649.4 million
, of which
$2,099.3 million
is senior notes,
$575.0 million
outstanding on the credit facility and a
$24.9 million
reduction related to the net original issue discount and unamortized debt issuance costs.
Significant Accounting Policies
Refer to
Note 2 – Revenue
in Part 1, Item 1 of this Quarterly Report on Form 10-Q for changes in QEP's revenue recognition policy as a result of the adoption of ASC Topic 606, effective January 1, 2018.