Item 1B.
Unresolved Staff Comments
None.
Information regarding our properties is included in Item 1 of this report.
Item 3.
Item 3.
Legal Proceedings
See Item 8 - Financial Statements and Supplementary Data-Note 11 of our Notes to Consolidated Financial Statements for the information that is called for by this item.
Item 4.
Item 4.
Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange under the ticker symbol “WPX”. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange.
At February 26, 2014, there were 8,477 holders of record of our common stock.
We have not paid or declared any cash dividends on our common stock. Any decision as to future payment of dividends is subject to the discretion of our Board of Directors.
Item 6.
Item 6.
Selected Financial Data
The following financial data at December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records. The financial statements included in this Form 10-K may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand-alone public company during all periods presented. Accordingly, our results for periods prior to 2012 should not be relied upon as an indicator of our future performance.
__________
(a)
Income (loss) from continuing operations for the year ended December 31, 2013 includes $1,055 million of impairment charges primarily related to producing properties in the Appalachian Basin and Powder River Basin and costs of acquired unproved reserves in the Powder River Basin and Piceance Basin. In addition, income (loss) from continuing operations for 2013 includes a $317 million impairment charge to estimated fair value of unproved leasehold costs in the Appalachian Basin, $20 million impairment on our equity method investment, as well as, a $36 million gain on the sale of leasehold for deep rights in the Powder River Basin. Income (loss) from continuing operations for the year ended December 31, 2012 includes $225 million of impairment charges related to producing properties in the Green River Basin and costs of acquired unproved reserves in the Piceance and Powder River Basins. Income (loss) from continuing operations for the year ended December 31, 2011 includes $367 million of impairment charges related to producing properties and costs of acquired unproved reserves in the Powder River Basin. Income (loss) from continuing operations for the year ended December 31, 2010 includes a $1 billion impairment charge related to goodwill and a $175 million impairment charge related to costs of acquired unproved reserves in the Piceance Basin. See Note 6 of Notes to Consolidated Financial Statements for further discussion of the impairments in 2013, 2012 and 2011.
(b)
Income (loss) from discontinued operations includes the results from holdings in the Barnett Shale and Arkoma Basin that were sold in 2012. The activity in the years 2009 through 2012 primarily relates to the Barnett Shale and Arkoma Basin operations. Activity in 2012 also reflects a $38 million pre-tax gain on the sale of the Barnett Shale and Arkoma Basin. Activity in 2011 and 2010 reflects pre-tax impairment charges of $180 million and $503 million, respectively, related to the Barnett Shale operations.
(c)
On June 30, 2011, all of our notes payable to Williams were canceled by Williams. The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in total equity that was partially offset by a $981 million cash distribution to Williams. See Part II, Item 8, Financial Statements and Supplementary Data for activity related to our equity at December 31, 2013 and 2012.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserves base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our oil positions in the Williston Basin in North Dakota and the San Juan Basin in the southwestern United States. Our other areas of domestic operations include natural gas plays in the Appalachian Basin in Pennsylvania, the San Juan Basin and the Powder River Basin in Wyoming. In addition, we own a 69 percent controlling ownership interest in Apco Oil and Gas International Inc. (“Apco”) which has oil and gas activities in South America and trades on the NASDAQ Capital Market under the symbol “APAGF”.
In conjunction with our exploration and development activities, we engage in sales and marketing activities that include the sale of our natural gas, oil and NGL production, along with third party purchases and sales of natural gas, which include natural gas purchased from working interest owners in operated wells and other area third party producers. Through May 1, 2012, this activity also included sales of natural gas to Williams Partners L.P. (“Williams Partners”) for use in its midstream business. Our sales and marketing activities also include the management of various natural gas related contracts such as transportation, storage and related price risk management activities. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in product revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses. Due to the seasonal aspects of the transportation and storage contracts utilized to manage our third party marketing obligations, our quarter to quarter results may vary with economic gains in the winter months and losses in the summer months.
WPX Energy, Inc. was formed in 2011 to effect the separation from The Williams Companies, Inc. (“Williams”) of Williams’ exploration and production business. The spin-off was completed by way of a pro rata distribution on December 31, 2011 of WPX common stock to Williams’ stockholders.
The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes included in Part II, Item 8 in this Form 10-K. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in “Risk Factors” and “Forward-Looking Statements”.
Basis of Presentation
The consolidated financial statements for 2011 included elsewhere in this Form 10-K, principally represent the Exploration & Production segment of Williams of which the legal entities were contributed to WPX in 2011. Through December 2011, our results included allocations of costs for corporate functions historically provided to us by Williams. See Note 3 of the Notes to Consolidated Financial Statements for more information.
Our management believes the assumptions and methodologies underlying the allocation of expenses from Williams were reasonable. However, such expenses may not be indicative of the actual level of expense that would have been or will be incurred by us as we operate as an independent, publicly traded company.
In second-quarter 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. These properties represented less than 5 percent of our year- end 2011 proved domestic reserves and approximately 5 percent of total production in 2011. We have reported the results of operations and financial position of Barnett Shale and Arkoma operations as discontinued operations. Unless otherwise noted, the following discussion relates to our continuing operations.
Overview
The following table presents our production volumes and financial highlights for 2013, 2012 and 2011:
__________
(a)
Excludes production from our Barnett Shale and Arkoma Basin operations which are classified as discontinued operations.
(b)
Oil and NGLs were converted to MMcfe using the ratio of one barrel of oil, condensate or NGL to six thousand cubic feet of natural gas.
(c)
Includes approximately 69 percent of Apco’s production (which corresponds to our ownership interest in Apco) and other minor directly held interests.
Our 2013 operating results were $1,468 million unfavorable as compared to 2012. The primary unfavorable impact includes $1.4 billion recorded in the fourth quarter 2013 for impairments of producing properties, costs of acquired unproved reserves and leasehold costs as compared to $225 million of impairments recorded in 2012 (see Note 6 of Notes to Consolidated Financial Statements). Significant declines in the forward natural gas prices relative to the forward prices at December 31, 2012 and more notably in the fourth quarter 2013, especially the Appalachia index prices, were the primary factors for the impairments. Additional unfavorable impacts include the absence of $423 million of gains realized in 2012 on natural gas derivatives designated as hedges for accounting purposes, $202 million unfavorable change in derivatives not designated as hedges, $90 million related to lower domestic natural gas production volumes and $85 million related to lower domestic NGL production volumes. Operating results were favorably impacted by $218 million related to higher domestic realized natural gas prices (excluding hedges), $168 million from higher domestic oil production volumes and prices (excluding hedges), $73 million lower gathering, processing and transportation costs, and a $36 million gain in 2013 on the sale of Powder River Basin deep rights leasehold.
While our total 2012 domestic production volumes increased over 2011, our 2012 results were impacted by lower realized natural gas prices (including hedges) coupled with lower natural gas liquids prices relative to 2011. Also, as a result of declines in forward natural gas prices during 2012 compared to 2011, we recorded impairments of producing properties and costs of acquired unproved reserves totaling $225 million during 2012. Our 2011 results were also impacted by impairment charges of $367 million on certain producing properties in 2011. See Note 6 of Notes to Consolidated Financial Statements.
Outlook
In 2014, we will continue our focus of growing our oil production and developing oil reserves, primarily those located in the Williston Basin and the Gallup Sandstone in the San Juan Basin. More than half of our planned 2014 capital expenditures are in domestic oil properties which includes a goal of 62 oil wells (gross) in the Williston Basin, an increase of 25 percent versus 2013, and 29 oil wells (gross) in the Gallup Sandstone which would nearly double 2013 activity.
We will also continue to focus our natural gas drilling effort in the Piceance Basin because of our scale and efficiency of that operation combined with significant infrastructure already in place. We have a goal of increasing our natural gas volumes over current production in the Piceance Basin by planning to deploy an average of nine drilling rigs in the Piceance Basin for 2014 which includes drilling focused on the Niobrara Shale discussed below. Our drilling program in the Appalachian Basin will be limited to completions in 2014. We are working to resolve constraints on our third party gatherer's system in Susquehanna County and may resume development in 2015.
We will continue to focus on lowering costs through reduced drilling times, efficient use of pad design and completion activities and negotiating cost savings on vendor contracts. Additionally, we are undertaking extensive review of our general and administrative costs and services.
Also in 2014, we will evaluate transactions that would monetize certain of our assets and enable us to redeploy the sales proceeds in areas where there is an opportunity for a higher return. These transactions could include the sale or contribution of mature, producing natural gas properties located in the Piceance to a master limited partnership (“MLP”). As previously announced, we have begun the process of forming an MLP although it is subject to final board approval and favorable market conditions.
Approximately 12 percent of our estimated annual capital spending in 2014 will be for exploratory activities, primarily for further delineation of our Niobrara Shale discovery in the Piceance Basin. We are also in the process of drilling test wells in other new areas. We will also continue to evaluate the purchase of leasehold in these and other areas. Our initial Niobrara Shale discovery well in the Piceance Basin produced 2.2 billion cubic feet of natural gas production in the first year of operation. We drilled four additional wells in 2013, two of which are producing, one that is a vertical test well and one that is being evaluated for alternatives due to a casing issue in the lateral section before completion began. Initial drilling thus far has validated the existence of a highly pressured continuous gas accumulation capable of producing pipeline-quality gas. Future drilling will focus on driving down costs while optimizing completion techniques. We plan to double our Niobrara delineation drilling in 2014 with up to 10 wells expected and we also initiated 3-D seismic work in the Piceance Valley to aid in the delineation. This activity will provide 70 percent seismic coverage of our Piceance Valley acreage.
We anticipate our total capital spending in 2014 will be up to $1.5 billion. The execution of transactions to monetize certain of our assets as previously mentioned is an important component to achieving the necessary capital to fund our spending program. If we are unable to successfully execute on assets sales, we may reduce our capital spending or make additional borrowings on our revolver. Our 2013 capital expenditures totaled approximately $1.15 billion.
We continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:
•
Continuing to invest in and grow our production and reserves;
•
Continuing to diversify our commodity portfolio through the development of our Williston Basin oil play position, Gallup Sandstone oil play and liquids-rich basins (primarily Piceance Basin) with high concentrations of NGLs;
•
Fully delineating Niobrara Shale potential through drilling and 3-D seismic;
•
Continuing to pursue cost improvements and efficiency gains;
•
Continuing to invest in exploration projects to add new development opportunities to our portfolio;
•
Retaining the flexibility to make adjustments to our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities; and
•
Continuing to maintain an active economic hedging program around our commodity price risks.
Potential risks or obstacles that could impact the execution of our plan include:
•
Lower than anticipated energy commodity prices;
•
Higher capital costs of developing our properties;
•
Lower than expected levels of cash flow from operations;
•
Lower than expected proceeds from asset sales;
•
Counterparty credit and performance risk;
•
General economic, financial markets or industry downturn;
•
Changes in the political and regulatory environments;
•
Increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation;
•
Decreased drilling success; and
•
Unavailability of capital.
Currently the forward natural gas prices for 2014 are higher than our realized prices for 2013. However, forward natural gas and oil prices for 2015 and after are lower than the 2014 prices. Changes in the forward prices will be considered as we proceed with our 2014 capital program. Additionally, if forward natural gas prices were to decline by 6 to 8 percent or forward oil prices were to decline by 11 to 13 percent as compared to the forward prices at December 31, 2013, we would need to review a substantial portion of the producing properties net book value for impairment. With the exception of potential impairments, we continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.
Commodity Price Risk Management
To manage the commodity price risk and volatility of owning producing gas and oil properties, we enter into derivative contracts for a portion of our future production. We have the following contracts as of February 26, 2014 for over 50 percent of our estimated daily domestic production in 2014, shown at weighted average volumes and basin-level weighted average prices:
Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We also hold an obligation, which expires in November 2014, to deliver on a firm basis 200,000 MMbtu/d of natural gas at monthly index pricing to a buyer at the White River Hub (Greasewood-Meeker, CO), which is a major market hub exiting the Piceance Basin. However, the price received is based on a Northeast
index and was less than the index price in the Rockies in 2013. Our interests in the Piceance Basin hold sufficient reserves to meet this obligation.
Results of Operations
Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments.
Domestic includes natural gas, oil and natural gas liquids development, production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania and Wyoming in the United States. Our development and production techniques specialize in production from tight-sands and shale formations as well as coal bed methane reserves in the Piceance, Williston, San Juan, Powder River, Appalachian and Green River Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
International primarily consists of our ownership in Apco, an oil and gas exploration and production company with activities primarily in Argentina and Colombia.
Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges for accounting purposes. Most of our commodity derivative contracts entered into after 2011 continue to serve as economic hedges but are not designated as hedges for accounting purposes as we have elected not to utilize hedge accounting on new derivatives instruments. Changes in the fair value of non-hedge derivative instruments, hereafter referred to as economic hedges, are recognized as gains or losses in the earnings of the periods in which they occur, accordingly we believe this will result in future earnings that are more volatile. The unrealized changes in fair value of cash flow hedge derivatives recorded in accumulated other comprehensive income at December 31, 2012 were realized at the end of first quarter 2013.
2013 vs. 2012
Revenue Analysis
_ ________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Domestic Revenues
Significant variances in the respective line items of domestic revenues are comprised of the following:
•
$272 million decrease in natural gas sales primarily due to the absence of $423 million of realized gains in 2012 from derivatives designated as hedges and $90 million related to lower production sales volumes offset by $218 million related to higher sales prices (excluding hedges). The Company no longer designated derivatives entered into after December 31, 2011 as hedges for accounting purposes. The decrease in our production sales volumes is due in part to our disciplined development of natural gas reserves in a low natural gas price environment. However, natural gas production in the Appalachian Basin has increased over prior year but third party infrastructure constraints are continuing. We also have increased drilling in the Piceance Basin that will increase production from current levels in that basin. Natural gas production from the Piceance Basin represents approximately 60 percent of our total domestic natural gas production. The following table reflects natural gas production prices and volumes for 2013 and 2012:
__________
(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.
•
$158 million increase in oil and condensate sales reflects increased production sales volumes as well as a higher price per barrel (including the impact of hedges in 2012) for 2013 compared to 2012. The increase in production sales volumes primarily relates to increased production in the Williston Basin where the per day volumes were 13.2 MBbls per day for 2013 compared to 9.5 MBbls per day for 2012. The San Juan Basin also had production of 0.8 MBbls per day for 2013. The following table reflects oil and condensate production prices and volumes for 2013 and 2012:
__________
(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.
•
$68 million decrease in natural gas liquids sales reflects decreased production sales volumes for 2013 compared to 2012, a portion of which relates to lower ethane recovery rates as a result of ethane prices in the Piceance Basin during 2013. The increased average per barrel price for natural gas liquids reflects a change in the composition of the barrel, as noted in the table below, due to lower ethane recovery rates. The following table reflects NGL production prices and volumes for 2013 and 2012:
__________
(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.
The following table summarizes the composition of the Piceance NGL barrel for 2013 and 2012:
•
$58 million decrease in gas management revenues is primarily due to lower commodity sales volumes partially offset by an increase in average prices on physical natural gas sales. We experienced a similar decrease of $65 million in related gas management costs and expenses.
•
$202 million change in net gain (loss) on derivatives not designated as hedges reflects both unrealized and realized losses on derivatives for 2013. The change in the unrealized loss for 2013 primarily relates to crude and natural gas derivatives as well as natural gas transportation hedges. The net change in the realized loss in 2013 primarily related to natural gas and NGL derivatives.
International Revenues
International revenues increased primarily due to the reinstatement of a government hydrocarbon subsidy program in Argentina in 2013.
Cost and operating expense and operating income (loss) analysis:
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Domestic Costs
Significant components on our domestic costs and expenses are comprised of the following:
•
$20 million increase in lease and facility operating expense primarily relates to increased water disposal costs due in part to decreased drilling in the Appalachian Basin and the corresponding utilization of produced water in the well hydraulic fracturing process. Additionally, increased Williston Basin production in relation to our overall portfolio impacted the increase in lease and facility operating expense. Lease and facility operating expense averaged $0.62 per Mcfe for 2013 compared to $0.52 per Mcfe in 2012.
•
$74 million decrease in gathering, processing and transportation charges primarily related to new favorable contract terms for gathering and processing services in the Piceance Basin as well as lower volumes. Gathering, processing and transportation expenses averaged $0.98 per Mcfe compared to $1.04 per Mcfe for 2013 and 2012, respectively. Gathering, processing and transportation for 2012 includes a $9 million adjustment related to royalty calculations for prior periods. Excluding this adjustment, gathering, processing and transportation expenses would have averaged $1.02 per Mcfe for 2012.
•
$30 million increase in taxes other than income from 2013 compared to 2012 relates to the increase in natural gas prices (excluding derivatives), increased crude oil production volumes and higher crude oil prices. Taxes other than income averaged $0.27 per Mcfe for 2013 compared to $0.18 per Mcfe for 2012.
•
$65 million decrease in gas management expenses reflect the lower commodity purchase volumes partially offset by an increase in average prices on physical natural gas cost of sales. Also included in gas management expenses are $61 million and $46 million for 2013 and 2012, respectively, for unutilized pipeline capacity. Gas management expenses for the period ended December 31, 2013 and 2012 included $1 million and $11 million, respectively, related to lower of cost or market charges to the carrying value of natural gas inventories in storage and 2013 includes $9 million related to the buyout of a transportation agreement.
•
$352 million higher exploration expense primarily relates to a $317 million impairment to fair value of leasehold in the Appalachian Basin in 2013 as well as higher leasehold amortization expense.
•
$33 million decrease in depreciation, depletion and amortization primarily due to lower production volumes in 2013 compared to 2012. Also during 2013, we have adjusted our proved reserves used for the calculation of depletion and amortization which resulted in a net $17 million reduction of depreciation, depletion and amortization expense for 2013. These adjustments primarily reflect the impact of an increase in the 12 month average price partially offset by reduced NGL reserves due to continued lower ethane recovery. During 2013 our depreciation, depletion and amortization averaged $2.06 per Mcfe compared to an average $1.93 per Mcfe in 2012. This increase partially reflects the growth of the Williston Basin as part of our portfolio.
•
$1,052 million in 2013 of impairments of producing properties and cost of acquired unproved reserves compared to $225 million for 2012, as previously discussed. (See Note 6 of Notes to Consolidated Financial Statements.)
•
$36 million gain on the sale of Powder River Basin deep rights leasehold in 2013.
•
General and administrative expense was relatively flat compared to 2012. Additionally, 2013 includes $4 million of costs associated with the separation of our chief executive officer. General and administrative expense averaged $0.62 per Mcfe compared to $0.56 per Mcfe for 2013 and 2012, respectively.
•
Other expenses for 2013 includes approximately $8 million for settlement of litigation. Rig release and standby fees were $12 million and $9 million for 2013 and 2012, respectively.
International costs
International costs increased primarily due to higher depreciation, depletion and amortization and higher production and lifting costs. Additionally, a $3 million impairment for property in Colombia was recorded in 2013.
Consolidated results below operating income (loss)
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
The increase in interest expense primarily relates to a higher amount outstanding on our revolver in 2013.
Our investment income and other primarily reflects equity earnings associated with our international and domestic equity method investments. In addition, 2013 includes a $20 million impairment related to an equity method investment in the Appalachian Basin. This impairment was a result of the 2013 impairment of the producing properties in the Appalachian Basin (see Notes 4 and 6 of Notes to Consolidated Financial Statements).
Benefit for income taxes changed favorably primarily due to greater pre-tax loss for 2013 compared to 2012. Income taxes in 2013 include a $80 million deferred tax provision related to the increase in a valuation allowance on certain state deferred tax assets. Income taxes in 2013 also included a $10 million provision related to the impact of the new capital tax law in Argentina. In September 2013, the Argentine government enacted tax reform legislation related to dividends and capital gains which will apply to the Argentine operations of our consolidated investment in Apco, a Cayman Islands corporation. The new 10 percent dividend tax will be accrued by Apco when dividends are paid by its Argentine investments in future periods. The capital gains tax applies to the sale of Argentine securities by a non Argentine resident, such as Apco, making such sales subject to an effective 13.5 percent tax on the gross proceeds. As a result, Apco recorded approximately $14 million of a foreign deferred tax expense during third quarter 2013 for the excess book basis over tax basis in its equity investment in Petrolera Entre Lomas S.A., of which approximately $12 million relates to basis differences that occurred prior to 2013. This accrual was partially offset by approximately $4 million of U.S. deferred tax benefit recorded by WPX related to the additional Argentine tax. See Note 10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Income from discontinued operations for 2012 reflects a $38 million pretax gain on sale in 2012.
The change in net income (loss) attributable to noncontrolling interests is primarily due to $11 million associated with the impairment of a certain Appalachian Basin facility asset as well as a $4 million impact in 2013 as a result of the new Argentine tax law.
2012 vs. 2011
Revenue Analysis
Domestic Revenues
Significant variances in the respective line items of domestic revenues are comprised of the following:
•
$332 million decrease in natural gas sales primarily reflects lower gas prices (including hedges) for 2012 compared to 2011. The following table reflects natural gas production prices and volumes for 2012 and 2011:
__________
(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.
•
$150 million increase in oil and condensate sales reflects increased production sales volumes for 2012 compared to 2011. The following table reflects oil and condensate production prices and volumes for 2012 and 2011:
__________
(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.
•
$108 million decrease in natural gas liquids sales reflects lower NGL prices for 2012 compared to 2011. The following table reflects natural gas liquid production prices and volumes for 2012 and 2011:
__________
(a) Included in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations.
•
$479 million decrease in gas management revenues due to a 27 percent decrease in average prices on physical natural gas sales and 9 percent lower natural gas sales volumes. We experienced a similar decrease of $475 million in related gas management costs and expenses.
•
$49 million change in net gain (loss) on derivatives not designated as hedges primarily relates to unrealized and realized mark-to-market gains on crude oil and natural gas derivatives not designated as hedges.
International Revenues
International revenues increased primarily due to increased oil sales due to higher average oil sales prices and new oil production in Colombia for 2012 compared to 2011.
Cost and operating expense and operating income (loss) analysis:
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Domestic Costs
Significant components on our domestic costs and expenses are comprised of the following:
•
Lease and facility operating expense in 2012 averaged $0.52 per Mcfe compared to $0.51 per Mcfe during 2011.
•
$17 million increase in gathering, processing and transportation expenses primarily as a result of an increase in natural gas liquids volumes. This increase includes a $9 million adjustment related to royalty calculations for prior periods. Excluding this adjustment, our gathering, processing and transportation charges averaged $1.02 per Mcfe for 2012 compared to an average of $1.05 for 2011.
•
$26 million decrease in taxes other than income for 2012 primarily reflecting the impact of decreased total product revenues (excluding hedges) resulting from lower commodity prices in 2012 compared to 2011. Our taxes other than income averaged $0.18 per Mcfe for 2012 compared to an average of $0.24 for 2011.
•
$475 million decrease in gas management expenses due to a 27 percent decrease in average prices on physical natural gas cost of sales and a 9 percent decrease in natural gas sales volumes. Also included in gas management expenses are $46 million and $35 million in 2012 and 2011, respectively, for unutilized pipeline capacity. Gas management expenses in 2012 and 2011 also include $11 million and $10 million, respectively, related to lower of cost or market charges to the carrying value of natural gas inventories in storage.
•
$51 million decrease in exploration expenses primarily reflects lower unproved leasehold impairment, amortization and expiration expenses in 2012 compared to 2011 which includes a $50 million write-off impairment of acreage in Columbia County, Pennsylvania that we no longer planned to develop. Additionally, in 2011 we incurred approximately $11 million of dry hole expenses in connection with a Marcellus Shale well in Columbia County because results were inconclusive and raised substantial doubt about the economic and operational viability of the well.
•
$59 million increase in depreciation, depletion and amortization expenses which reflects higher production volumes and a slightly higher rate. During 2012 our depreciation, depletion and amortization averaged $1.93 per Mcfe compared to an average $1.89 per Mcfe in 2011. During the course of 2012, we adjusted our estimated proved reserves used for the calculation of depletion and amortization to reflect the impact of the decrease in the 12 month average price; this resulted in a total of approximately $31 million additional depreciation, depletion and amortization expense in 2012 and was the main driver of the increase in the average per Mcfe.
•
$225 million of property impairments in 2012 compared to $367 million in 2011, as previously discussed.
•
The increase in other-net expense for 2012 primarily reflects $9 million in rig release penalties and rig standby fees.
International costs
International costs increased primarily due to higher exploration expenses related to 3-D seismic acquisition costs and dry hole expenses. Costs also increased due to higher depreciation, depletion and amortization and higher production and lifting costs.
Consolidated results below operating income (loss)
__________
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Interest expense in 2012 primarily reflects interest accrued on our senior notes issued in November 2011. Interest expense in 2011 primarily reflects interest through June 30, 2011 associated with our unsecured notes payable with Williams. The outstanding amounts were cancelled by Williams and contributed to capital on June 30, 2011. Additionally, interest expense in 2011 also includes $11 million of interest on our senior notes issued in November 2011.
Our investment income and other primarily reflects equity earnings associated with our international and domestic equity method investments.
The benefit for income taxes increased in 2012 from 2011 due to an increased loss from continuing operations. See Note 10 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Income (loss) from discontinued operations reflects a $38 million pretax gain on sale in 2012 and a $209 million pretax impairment in 2011. As previously discussed, we completed the sale of our holdings in Barnett Shale and the Arkoma Basin during 2012. See Note 2 of Notes to Consolidated Financial Statements.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview and Liquidity
In 2013 we continued to focus upon growth through continued disciplined investments in expanding our natural gas, oil and NGL portfolio.
Our main sources of liquidity are cash on hand, internally generated cash flow from operations and our bank credit facility. Additional sources of liquidity, if needed and if available, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. Prior to December 1, 2011, our liquidity was managed through an internal cash management program with Williams. Daily cash activity from our domestic operation was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011, at which time the notes were canceled by Williams. Any cash activity from July 1, 2011 until November 30, 2011 was treated as capital contribution. On December 1, 2011, we began to manage our own cash beginning with the $500 million retained after the issuance of the senior notes. In consideration of our liquidity, we note the following:
•
As of December 31, 2013, we maintained liquidity through cash, cash equivalents and available credit capacity under our credit facility.
•
Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support.
•
Apco’s liquidity requirements have historically been provided by its cash flows from operations and cash on hand. Included in our cash and cash equivalents at December 31, 2013 is $51 million related to our international operations.
Outlook
We expect our capital structure will provide us financial flexibility to meet our requirements for working capital, capital expenditures, and tax and debt payments while maintaining a sufficient level of liquidity. Our primary sources of liquidity in 2014 are expected cash flows from operations, proceeds from monetization of assets, including the potential formation of an MLP, and additional borrowings on our $1.5 billion credit facility. The combination of these sources should be sufficient to allow us to pursue our business strategy and goals for 2014.
We note the following assumptions for 2014:
•
Our capital expenditures, including international, are estimated to be up to $1.5 billion in 2014 and are generally considered to be largely discretionary; and
•
Apco’s liquidity requirements will continue to be provided from its cash flows from operations and cash on hand.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
•
Lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices;
•
Lower than expected proceeds from asset sales;
•
Higher than expected collateral obligations that may be required, including those required under new commercial agreements;
•
Significantly lower than expected capital expenditures could result in the loss of undeveloped leaseholds; and
•
Reduced access to our credit facility.
Under the credit facility agreement (“Credit Facility Agreement”) and prior to our receipt of an investment grade rating with a stable outlook, we are required to maintain a ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness (as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. Net present value is determined as of the end of each fiscal year and reflects the present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (such cash flows are adjusted to reflect the impact of hedges, our lenders’ commodity price forecasts, and, if necessary, to include only a portion of our reserves that are not proved developed producing reserves). See Note 9 of Notes to Consolidated Financial Statements. We are in the process of completing the net present value calculation due by April 20, 2014, however, we believe that we will have full access to the $1.5 billion in 2014. Further declines in natural gas prices during future years could reduce our net present value and thus limit our available capacity under the agreement.
We have executed three bilateral, uncommitted letter of credit agreements which we anticipate will be renewed annually. These agreements allow us to preserve our liquidity under our revolving credit agreement while providing support to our ability to meet performance obligation needs for, among other items, various interstate pipeline contracts into which we have entered. These unsecured agreements incorporate similar terms as those in the Credit Facility Agreement. At December 31, 2013, a total of $361 million in letters of credit have been issued.
Credit Ratings
Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analysis when assigning credit ratings. A downgrade of our current rating could increase our future cost of borrowing and result in a requirement that we post additional collateral with third parties, thereby negatively affecting our available liquidity. The current ratings are as follows:
__________
(a)
A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
(b)
A rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1,” “2,” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates the lower end of the category.
Sources (Uses) of Cash
Operating activities
Our net cash provided by operating activities in 2013 decreased from 2012 primarily due to the decrease in our operating results driven by lower natural gas (including the impact of hedges) and NGL sales revenues.
The decrease in net cash provided by operating activities in 2012 from 2011 is primarily due to lower realized commodity prices.
Investing activities
Significant items include expenditures for drilling and completion of approximately $1.0 billion, $1.2 billion and $1.4 billion in 2013, 2012 and 2011, respectively. Also included, are proceeds of $36 million from the sale of deep rights in the Powder River Basin in 2013 and $306 million from the sale of our holdings in the Barnett Shale and Arkoma Basin in 2012.
Financing activities
Net cash provided by financing activities in 2013 includes $410 million net borrowings on our credit facility.
Net cash provided by financing activities in 2012 includes $10 million of a contribution from a third party related to the formation of a consolidated limited liability company. This company was formed to hold gathering facilities.
Net cash provided by financing activities in 2011 includes $1.5 billion Note proceeds in November 2011 and $159 million in borrowings from Williams prior to July 2011. Partially offsetting these proceeds was a $981 million distribution to Williams in November 2011.
Off-Balance Sheet Financing Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at December 31, 2013 and December 31, 2012.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2013.
__________
(a)
Includes materials and services obligations associated with our drilling rig contracts.
(b)
Excludes additional commitments totaling $58 million associated with projects for which the counterparty has not yet received satisfactory regulatory approvals or, for other business reasons, has not yet begun construction.
(c)
Purchase commitments are at market prices and the purchased natural gas can be sold at market prices. The obligations are based on market information as of December 31, 2013 and contracts are assumed to remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur. In 2013, certain parties converted their gas purchase agreements to firm gathering and processing agreements, which services will be provided by Williams Partners. WPX Energy’s gas purchase obligations totaling $1.2 billion at December 31, 2012 terminated at the effective date of the new agreements.
(d)
Includes gathering, processing and other oil and gas related services commitments. Excluded are liabilities associated with asset retirement obligations, which total $364 million as of December 31, 2013. The ultimate settlement and timing cannot be precisely determined in advance; however, we estimate that approximately 6 percent of this liability will be settled in the next five years.
(e)
Includes $2.6 billion of physical natural gas derivatives related to purchases at market prices. The natural gas expected to be purchased under these contracts can be sold at market prices, largely offsetting this obligation. The obligations for physical and financial derivatives are based on market information as of December 31, 2013, and assume contracts remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur.
Effects of Inflation
Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Operating costs are influenced by both competition for specialized services and specific price changes in natural gas, oil, NGLs and other commodities. We tend to experience inflationary pressure on the cost of services and equipment as increasing oil and gas prices increase drilling activity in our areas of operation.
Environmental
Our operations are subject to governmental laws and regulations relating to the protection of the environment, and increasingly strict laws, regulations and enforcement policies, as well as future additional environmental requirements, could materially increase our costs of operation, compliance and any remediation that may become necessary.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are as follows:
Impairments of Long-Lived Assets
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that include the undiscounted future cash flows, discounted future cash flows, estimated fair value of the asset, and the current and future economic environment in which the asset is operated.
Due to the drop in natural gas and natural gas liquids forward prices during 2013 and more significantly in the fourth quarter, we assessed our natural gas producing properties and acquired unproved reserve costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of reserves quantities, estimates of future commodity prices (primarily natural gas, using a forward NYMEX curve adjusted for locational basis differentials) drilling plans, expected capital costs and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. The assessment performed identified certain properties with a carrying value in excess of those undiscounted cash flows and their calculated fair values. As a result, we recognized $1,055 million of impairment charges in 2013. See Notes 6 and 15 of Notes to Consolidated Financial Statements for additional discussion and significant inputs into the fair value determination.
In addition to those long-lived assets described above for which impairment charges were recorded, certain others were reviewed for which no impairment was required. These reviews included other domestic producing properties and acquired unproved reserve costs, and utilized inputs generally consistent with those described above. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. For other producing assets reviewed, but for which impairment charges were not recorded, we estimate that approximately 64 percent could be at risk for impairment if forward natural gas and NGL prices across all future periods decline by approximately 6 percent to 8 percent, on average, as compared to the forward commodity prices at December 31, 2013. We estimate that
approximately 28 percent could be at risk for impairment if forward oil prices across all periods decline by approximately 11 percent to 13 percent.
Accounting for Derivative Instruments and Hedging Activities
Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, new commodity derivative contracts that serve as economic hedges of production will not be designated as hedges for accounting purposes as we have elected not to utilize hedge accounting on new derivatives instruments. Changes in the fair value of derivative instruments, hereafter referred to as economic hedges or derivatives not designated as hedges, are recognized as gains or losses in the earnings of the periods in which they occur, accordingly we believe this will result in future earnings that are more volatile. The unrealized changes in fair value of cash flow hedge derivatives recorded in accumulated other comprehensive income at December 31, 2012 were realized at the end of the first-quarter 2013.
We review our energy contracts to determine whether they are, or contain, derivatives. Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short-term, with more than 99 percent of the value of our derivatives portfolio expiring in the next 13 months. We further assess the appropriate accounting method for any derivatives identified, which could include:
•
applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings;
•
qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or
•
qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings for derivatives entered into prior to 2012.
If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the accounting method involves significant judgments and assumptions, which are further described below.
The determination of whether a derivative contract qualifies as a cash flow hedge included an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assessed whether the hedged forecasted transaction is probable of occurring. This assessment required us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur and the quantity of the forecasted transaction. In addition, we compared actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.
For derivatives designated as cash flow hedges, we must periodically assess whether they continue to qualify for hedge accounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we reclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.
Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.
Since our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivatives, as generally depicted below:
Consolidated Statements of Operations
Consolidated Balance Sheets
Accounting Method
Drivers
Impact
Drivers
Impact
Accrual
Accounting
Realizations
Less Volatility
None
No Impact
Cash Flow Hedge
Accounting
Realizations &
Ineffectiveness
Less Volatility
Fair Value Changes
More Volatility
Mark-to-Market Accounting
Fair Value Changes
More Volatility
Fair Value Changes
More Volatility
Our determination of the accounting method does not impact our cash flows related to derivatives.
Additional discussion of the accounting for energy contracts at fair value is included in Notes 1 and 16 of Notes to Consolidated Financial Statements.
Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities
We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:
•
An increase (decrease) in estimated proved natural gas, oil and NGL reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and
•
Changes in natural gas, oil and NGL reserves and forward market prices both impact projected future cash flows from our properties. This, in turn, can impact our periodic impairment analyses.
The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, over 99 percent of our domestic reserves estimates are audited by independent experts. The data may change substantially over time as a result of numerous factors, including additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserves estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $80 million and $98 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserves categories.
Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the forward price curve could result in an impairment of our oil and gas properties.
We record the cost of leasehold acquisitions as incurred. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. Changes in our assumptions regarding the estimates of the nonproductive portion of these leasehold acquisitions could result in impairment of these costs. Upon determination that specific acreage will not be developed, the costs associated with that acreage would be impaired. Additionally, our leasehold costs are evaluated for impairment if the proved property costs in the basin are impaired. Our capitalized lease acquisition costs, including costs of acquired unproved reserves, totaled $382 million at December 31, 2013.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including royalty litigation, environmental and other contingent matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 11 of Notes to Consolidated Financial Statements.
Valuation of Deferred Tax Assets and Liabilities
We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. Included in our deferred taxes are deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of book basis, from certain separate state losses generated in the current and prior years and, effective with the spin-off, from certain tax attributes allocated between us and Williams. We must periodically evaluate whether it is more likely than not we will realize these deferred tax assets and establish a valuation allowance for those that do not meet the more likely than not threshold. When assessing the need for a valuation allowance, we consider future reversals of existing taxable temporary differences, future taxable income exclusive of reversing temporary differences and carryforwards, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryforwards. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.
The determination of our state deferred tax requires judgment as we did not exist as a stand-alone filer in all states prior to the spin-off and the state deferred tax can change periodically based on changes in our operations. Our state deferred tax is based upon our current entity structure and the jurisdictions in which we operate.
See Note 10 of Notes to Consolidated Financial Statements for additional information.
Fair Value Measurements
A limited amount of our energy derivative assets and liabilities trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value for our energy derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities, we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2013, the credit reserve is less than $1 million on our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.
At December 31, 2013, 92 percent of the fair value of our derivatives portfolio expires in the next 12 months and more than 99 percent expires in the next 24 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.
The instruments included in Level 3 at December 31, 2013, consist of natural gas index transactions that are used to manage the physical requirements of our business. The change in the overall fair value of instruments included in Level 3
primarily results from changes in commodity prices during the month of delivery. There are generally no active forward markets or quoted prices for natural gas index transactions.
For the years ended December 31, 2013, 2012 and 2011, we recognized impairments of certain assets that were measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. See Note 15 of Notes to Consolidated Financial Statements.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our interest rate risk exposure is related primarily to our debt portfolio. Our senior notes are fixed rate debt in order to mitigate the impact of fluctuations in interest rates. For our fixed rate debt, $400 million matures in 2017 and $1,100 million matures in 2022. Interest rates for each group are 5.25 percent and 6.00 percent, respectively. The aggregate fair value of the senior notes is $1,528 million. Borrowings under our credit facility are based on a variable interest rate and could expose us to the risk of increasing interest rates. As of December 31, 2013, the weighted average variable interest rate was 2.27 percent on the $410 million outstanding under the Credit Facility Agreement. See Note 9 of Notes to Consolidated Financial Statements.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of natural gas, oil and NGLs, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Notes 15 and 16 of Notes to Consolidated Financial Statements.
We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
Trading
Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net liability of $1 million at December 31, 2013 and a net asset of $1 million at December 31, 2012. The value at risk for contracts held for trading purposes was less than $1 million at December 31, 2013 and December 31, 2012.
Nontrading
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our natural gas purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net liability of $64 million at December 31, 2013 and a net asset of $39 million at December 31, 2012.
The value at risk for derivative contracts held for nontrading purposes was $19 million at December 31, 2013, and $6 million at December 31, 2012. During the year ended December 31, 2013, our value at risk for these contracts ranged from a high of $19 million to a low of $12 million. The increase in value at risk from December 31, 2012 primarily reflects new derivative contracts entered into to hedge our equity production.
Item 8.
Item 8.
Financial Statements and Supplementary Data
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Based on our assessment, we concluded that, as of December 31, 2013, our internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.
Report of Independent Registered Public Accounting Firm on
Internal Control over Financial Reporting
The Board of Directors and Shareholders of WPX Energy, Inc.
We have audited WPX Energy, Inc. internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). WPX Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, WPX Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of WPX Energy, Inc. as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2013, of WPX Energy, Inc. and our report dated February 27, 2014, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 27, 2014
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of WPX Energy, Inc.
We have audited the accompanying consolidated balance sheets of WPX Energy, Inc. as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15.(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of WPX Energy, Inc. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), WPX Energy, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 27, 2014, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 27, 2014
WPX Energy, Inc.
Consolidated Balance Sheets
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Operations
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Comprehensive Income (Loss)
__________
(a)
Change in fair value of cash flow hedges is net of income tax of $33 million and $151 million for 2012 and 2011, respectively. 2012 includes a $15 million before tax unrealized gain that was recognized in net gain (loss) on derivatives not designated as hedges on the Consolidated Statements of Operations, as the underlying transaction was no longer probable of occurring (see Note 16).
(b)
Net reclassifications into earnings of net cash flow hedge realized gains are net of $2 million, $159 million and $120 million of income tax for 2013, 2012 and 2011, respectively. Before tax amounts realized and reclassified to product revenues, primarily natural gas sales revenues, on the Consolidated Statements of Operations were $5 million, $434 million and $331 million for 2013, 2012 and 2011, respectively.
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Changes in Equity
__________
(a)
Primarily represents the 31 percent of Apco Oil and Gas International Inc. owned by others.
See accompanying notes.
WPX Energy, Inc.
Consolidated Statements of Cash Flows
See accompanying notes.
WPX Energy, Inc.
Notes to Consolidated Financial Statements
Note 1. Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business
Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments. WPX Energy, Inc. was formed in 2011 by The Williams Companies, Inc. (“Williams”) to effect the separation of its exploration and production business. Williams contributed to the Company its investment in certain subsidiaries related to Williams’ domestic and international exploration and production businesses, collectively referred to as the “Contribution”. The separation was completed on December 31, 2011 through a pro rata distribution of WPX common stock to Williams’ stockholders.
Domestic includes natural gas, oil and NGL development, production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania and Wyoming in the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, Williston, San Juan, Powder River, Appalachian and Green River Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
International primarily consists of our ownership in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we”, “us” or “our”.
Basis of Presentation
These financial statements are prepared on a consolidated basis. Prior to the Contribution, the financial statements were derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the Contribution to WPX. Management believes the assumptions underlying the financial statements are reasonable. The financial statements of 2011 included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during 2011. Because a direct ownership relationship did not exist prior to the Contribution among the various entities that comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, has been shown as Williams’ net investment within stockholder’s equity in the consolidated financial statements. In connection with the Contribution, we have reflected the amounts previously presented as Williams’ net investment in excess of the par value of our common stock as additional paid-in capital. Transactions in 2011 with Williams’ other operating businesses, which generally settled monthly, are shown as changes in accounts receivable or accounts payable in the Consolidated Statements of Cash Flows for the year ended December 31, 2011. Other transactions during the period prior to separation between the Company and Williams which were not part of the notes payable to Williams have been identified in the Consolidated Statements of Equity as net transfers with Williams (see Note 3).
Discontinued operations
During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. We have reported the results of operations and financial position of the Barnett Shale and Arkoma Basin operations as discontinued operations for all periods presented.
Additionally, see Note 11 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
•
Impairment assessments of long-lived assets;
•
Valuations of derivatives;
•
Estimation of natural gas and oil reserves;
•
Assessments of litigation-related contingencies; and
•
Asset retirement obligations.
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash of our domestic operations consists of approximately $21 million and $19 million at December 31, 2013 and 2012, respectively, primarily related to escrow accounts established as part of the settlement agreement with certain California utilities and is included in other current and noncurrent assets. Included in the separation and distribution agreement with Williams are indemnifications requiring us to pay to Williams any net asset (or receive any net liability) that result upon ultimate resolution of these matters (see Note 11). Additionally, restricted cash of our international segment consists of approximately $6 million and $9 million at December 31, 2013 and 2012, respectively, associated with various letters of credit that is also classified in other current and other noncurrent assets.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our inventories consist of tubular goods and production equipment for future transfer to wells of $49 million and $42 million at December 3l, 2013 and 2012, respectively. Additionally, we have natural gas in storage related to our gas management activities of $13 million and $24 million at December 31, 2013 and 2012, respectively, and crude oil production in transit of $10 million at December 31, 2013. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recognized lower of cost or market writedowns on natural gas in storage of $1 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Other capitalized costs
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis for our domestic properties or on a concession basis for our international properties. International concession reserve estimates are limited to production quantities estimated through the life of the concession. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other-net.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows.
Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Contingent liabilities
Owing to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under our credit facilities are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
•
Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;
•
The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
•
Realized gains and losses on all derivatives that settle financially;
•
Realized gains and losses on derivatives held for trading purposes; and
•
Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2013 and 2012 was insignificant. Additionally, natural gas revenues include $5 million, $423 million and $326 million in 2013, 2012 and 2011, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities through May 2012 included purchases and subsequent sales to Williams Partners for fuel and shrink gas (see Note 3). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
Charges for unutilized transportation capacity included in gas management expenses were $61 million, $46 million and $35 million in 2013, 2012 and 2011, respectively.
Capitalization of interest
We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used until June 30, 2011 was the rate charged to us by Williams through June 30, 2011, at which time our intercompany note with Williams was forgiven (see Note 3). We did not capitalize interest for the period from July 1, 2011 to mid November 2011. Beginning November 2011, we began using the weighted average rate of our long-term notes payable which were issued in November 2011 (see Note 9).
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. Through the effective date of the spin-off, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provisions for 2011 were
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
calculated on a separate return basis for us and our subsidiaries, except for certain adjustments. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.
Employee stock-based compensation
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Through the date of the spin-off, certain employees providing direct service to us participated in Williams’ common-stock-based awards plans. The plans provided for Williams’ common-stock-based awards to both employees and Williams’ non-management directors. The plans permitted the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards were granted for no consideration other than prior and future services or based on certain financial performance targets.
Through the date of the spin-off, Williams charged us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation was also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.
In preparation for the spin-off, Williams’ Compensation Committee determined that all outstanding Williams’ equity-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (“Pre-2006 Options”) would convert into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options were converted into options covering both Williams and WPX common stock. The number of shares underlying each award and, with respect to options, the per share exercise price of each such award has been adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of such awards.
Foreign exchange
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 5).
Note 2. Discontinued Operations
During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.
Summarized Results of Discontinued Operations
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
The impairments in 2011 reflect write-downs to estimates of fair value of our holdings in the Barnett Shale and the Arkoma Basin. Impairment charges on our Fort Worth (Barnett Shale) properties were $180 million in 2011. Impairment charges in Arkoma were $29 million in 2011. These nonrecurring fair value measurements, which fall within Level 3 of the fair value hierarchy, utilized a probability-weighted discounted cash flow analysis that was based on internal cash flow models.
Note 3. Transactions with Williams
During the fourth quarter of 2011, the Contribution and recapitalization of the Company was completed, whereby common stock held by Williams converted into approximately 197 million shares of WPX common stock. We also entered into agreements with Williams in connection with our separation. These agreements include:
•
A Separation and Distribution agreement for, among other things, the separation from Williams and the distribution of WPX common stock, the distribution of a portion of the net proceeds from the debt financing as well as agreements between us and Williams, including those relating to indemnification;
•
A tax sharing agreement, providing for, among other things, the allocation between Williams and WPX of federal, state, local and foreign tax liabilities for periods prior to the distribution and in some instances for periods after the distribution;
•
An employee matters agreement discussed below; and
•
A transition services agreement for one year following separation.
Personnel and related services
As previously discussed, our domestic operations were contributed to WPX Energy, Inc. on July 1, 2011. On June 30, 2011, certain entities that were contributed to us on July 1, 2011 withdrew from the Williams’ benefit plans and terminated their personnel services agreements with Williams’ payroll companies.
Simultaneously, two new administrative service entities owned and controlled by Williams executed new personnel services agreements with the payroll companies and joined the Williams plans as participants. The effect of these transactions is that none of the companies contributed to WPX Energy in June 2011 had any employees. Through December 30, 2011, these service entities employed all personnel that provided services to the Company and remained owned and controlled by Williams.
In connection with the spin-off, we entered into an Employee Matters Agreement with Williams that set forth our agreements with Williams as to certain employment, compensation and benefits matters. The Employee Matters Agreement provides for the allocation and treatment of assets and liabilities arising out of employee compensation and benefit programs in which our employees participated prior to January 1, 2012. In connection with the spin-off, we provided benefit plans and arrangements in which our employees will participate going forward. Generally, other than with respect to equity compensation (discussed below), from and after January 1, 2012, we sponsored and maintained employee compensation and benefit programs relating to all employees who transferred to us from Williams in connection with the spin-off through the contribution of two newly established service entities that employees of Williams were moved to prior to the spin-off. The Employee Matters Agreement provides that Williams will remain solely responsible for all liabilities under The Williams Companies Pension Plan, The Williams Companies Retirement Restoration Plan and The Williams Companies Investment Plus Plan. No assets and/or liabilities under any of those plans transferred to us or our benefit plans and our employees ceased active participation in those plans as of January 1, 2012.
All outstanding Williams equity awards (other than stock options granted prior to January 1, 2006) held by our employees as of the spin-off were converted into WPX equity awards, issued pursuant to a plan that we established (see Note 13). In addition, outstanding Williams stock options that were granted prior to January 1, 2006 and held by our employees and Williams’ other employees as of the date of the spin-off were converted into options to acquire both WPX common stock and Williams common stock, in the same proportion as the number of shares of WPX common stock that each holder of Williams common stock received in the spin-off. The conversion maintained the same intrinsic value as the applicable Williams equity award as of the date of the conversion.
Through the date of the spin-off, Williams charged us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carried the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs was charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Consolidated Statements of Operations.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
In addition, Williams charged us for certain employees of Williams who provided general and administrative services on our behalf (referred to as indirect employees). These charges were either directly identifiable or allocated to our operations. Direct charges included goods and services provided by Williams at our request. Allocated general corporate costs were based on our relative usage of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses was reflected in general and administrative expense in the accompanying Consolidated Statements of Operations. In management’s estimation, the allocation methodologies used were reasonable and resulted in a reasonable allocation to us of our costs of doing business incurred by Williams.
Other arrangements with Williams or its affiliates
We also have operating activities with Williams Partners and another Williams subsidiary. Beginning January 1, 2012, Williams and its subsidiaries were no longer related parties, therefore only amounts related to 2011 are disclosed as related parties. For 2011, the following were considered related party transactions. Our revenues include revenues from the following types of transactions:
•
Sales of NGLs related to our production to Williams Partners at market prices at the time of sale and included within our oil and gas sales revenues; and
•
Sales to Williams Partners and another Williams subsidiary of natural gas procured by WPX Energy Marketing for those companies’ fuel and shrink replacement at market prices at the time of sale and included in our gas management revenues.
Our costs and operating expenses include the following services provided by Williams Partners:
•
Gathering, treating and processing services under several contracts for our production primarily in the San Juan and Piceance Basins; and
•
Pipeline transportation for both our oil and gas sales and gas management activities which included commitments totaling $401 million at December 31, 2011.
We have managed a transportation capacity contract for Williams Partners. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, Williams Partners reimburses us for these transportation costs. These reimbursements to us totaled approximately $11 million for the year ended December 31, 2011, and are included in gas management revenues. We signed an agreement with Williams Partners under which these contracts were assigned to them effective May 1, 2012.
Prior to December 1, 2011, we participated in Williams’ centralized approach to cash management and the financing of its businesses. Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011, at which time the notes were cancelled by Williams.
The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in owner’s net investment. Through fourth-quarter 2011, an additional $162 million was cancelled and reflected as an increase in owner’s net investment. The notes reflected interest based on Williams’ weighted average cost of debt and such interest was added monthly to the note principle. The interest rate for the notes payable to Williams was 8.08 percent at June 30, 2011.
On August 25, 2011, we entered into a 10.5 year lease for our present headquarters office with Williams Headquarters Building Company, a direct subsidiary of Williams. We estimate the annual rent payable by us under the lease to be approximately $4 million per year.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Below is a summary for 2011 of the transactions with Williams or its affiliates (including amounts in discontinued operations) discussed above:
Note 4. Investment Income and Other
Investment income
The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.
Investments
Petrolera Entre Lomas S.A. operates several development concessions in South America. Other is comprised of investments in miscellaneous gas gathering interests in the United States.
Dividends and distributions received from companies accounted for by the equity method were $7 million, $12 million and $17 million in 2013, 2012 and 2011, respectively.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 5. Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidiltive due to our loss from continuing operations attributable to WPX Energy, Inc.
On December 31, 2011, 197.1 million shares of our common stock were distributed to Williams’ shareholders in conjunction with our spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount of common stock to be outstanding as of the beginning of 2011 in the calculation of basic and diluted weighted average shares.
The table below includes information related to stock options that were outstanding at December 31, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
__________
(a)
Our stock began trading on the New York Stock Exchange on January 3, 2012; therefore, a fourth quarter weighted-average market price is not available for 2011.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 6. Asset Sales, Impairments and Exploration Expenses
In 2013, we recorded a total of $1.4 billion in impairment charges of which $1,055 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expense and $20 million is included in investment income and other (see Note 4). These impairments are discussed further in the sections below.
Impairments and Asset Sales
The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, gain on sale, and other-net within costs and expenses. These significant adjustments are primarily associated with our domestic operations.
__________
(a)
Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded the following impairments during 2013:
•
$772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin;
•
$192 million impairment in the fourth quarter including $107 million of proved producing oil and gas properties and $85 million of the capitalized costs of acquired unproved reserves in the Powder River Basin;
•
$88 million impairment in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area; and,
•
$3 million impairment in the fourth quarter on property in Colombia.
As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded impairments of $48 million of proved producing oil and gas properties in the Green River Basin. Additionally, we recorded a total of $102 million and $75 million in impairments of capitalized costs of acquired unproved reserves primarily in the Powder River Basin and Piceance Basin, respectively. Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and reserves quantities (see Note 15).
As part of our assessment for impairments primarily resulting from declining forward natural gas prices during the fourth-quarter 2011, we recorded a $276 million impairment of proved producing oil and gas properties in the Powder River Basin (see Note 15). Additionally, we recorded a $91 million impairment of our capitalized cost of acquired unproved reserves in the Powder River Basin.
Our impairment analyses included an assessment of undiscounted (except for the costs of acquired unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 15).
In October 2013, we completed the sale of deep rights leasehold on approximately 140,000 net acres in the Powder River Basin for $36 million. This sale did not include our producing coal bed methane assets in the Powder River Basin.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Exploration Expenses
The following table presents a summary of exploration expenses.
Dry hole costs in 2011 reflect an $11 million dry hole expense in connection with a Marcellus Shale well in Columbia County, Pennsylvania.
Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold, while 2011 includes a $50 million write-off of leasehold costs associated with certain portions of our Columbia County, Pennsylvania acreage that we did not plan to develop. The $317 million impairment is associated with our impairment of the producing properties in the Appalachian Basin.
Note 7. Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
__________
(a)
Estimated useful lives are presented as of December 31, 2013.
(b)
Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c)
Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Unproved properties consist primarily of non-producing leasehold in the Appalachian Basin and the Williston Basin and costs of acquired unproved reserves in the Powder River and Piceance Basins.
Construction in progress includes $15 million in 2013 and $44 million in 2012 related to wells located in the Powder River Basin. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production. Additionally, construction in progress in 2013 includes $24 million related to exploratory well costs pending the determination of proved reserves.
Asset Retirement Obligations
Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
A rollforward of our asset retirement obligations for the years ended 2013 and 2012 is presented below.
__________
(a)
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
Estimate revisions in 2013 are primarily associated with increases in anticipated plug and abandonment costs.
Note 8. Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
Accrued and other current liabilities
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Note 9. Debt and Banking Arrangements
As of the indicated dates, our debt consisted of the following:
__________
(a)
Interest paid on debt totaled $91 million and $58 million for 2013 and 2012, respectively.
Senior Notes
In November 2011, we issued $1.5 billion in face value Senior Notes (“the Notes”). The Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the Notes were approximately $1.481 billion after deducting the initial purchasers’ discounts and our offering expenses. We retained $500 million of the net proceeds from the issuance of the Notes and distributed the remainder of the net proceeds from the issuance of the Notes, approximately $981 million, to Williams in connection with the Contribution.
Optional Redemption. We have the option, prior to maturity, in the case of the 2017 notes, and prior to October 15, 2021 (which is three months prior to the maturity date of the 2022 notes) in the case of the 2022 notes, to redeem all or a portion of the Notes of the applicable series at any time at a redemption price equal to the greater of (i) 100% of their principal amount and (ii) the discounted present value of 100% of their principal amount and remaining scheduled interest payments, in either case plus accrued and unpaid interest to the redemption date. We also have the option at any time on or after October 15, 2021, to redeem the 2022 notes, in whole or in part, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest thereon to the redemption date.
Change of Control. If we experience a change of control (as defined in the indenture governing the Notes) accompanied by a rating decline with respect to a series of Notes, we must offer to repurchase the Notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the indenture restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indenture also requires us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indenture. However, these limitations and requirements will be subject to a number of important qualifications and exceptions. The indenture does not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default. Each of the following is an “Event of Default” under the indenture with respect to the Notes of any series:
(1) a default in the payment of interest on the Notes when due that continues for 30 days;
(2) a default in the payment of the principal of or any premium, if any, on the Notes when due at their stated maturity, upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
Notes Registration. In June 2012, we completed an exchange offer whereby we exchanged our privately-placed Notes for like principal amounts of registered 5.250% Senior Notes due 2017 and 6.000% Senior Notes due 2022. The exchange offer fulfilled our obligations under the registration rights agreement that we entered into as part of the November 2011 issuance.
Credit Facility Agreement
During 2011, we entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. As of December 31, 2013, the weighted average variable interest rate was 2.27 percent on the $410 million outstanding under the Credit Facility Agreement. Subsequent to December 31, 2013, we have borrowed an additional net amount of $195 million under the Credit Facility Agreement.
Interest on borrowings under the Credit Facility Agreement will be payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Applicable Rate changes depending on which interest rate we select and our credit rating. Additionally, we will be required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility Agreement.
Under the Credit Facility Agreement, prior to the occurrence of the Investment Grade Date (as defined below), we will be required to maintain a ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness (each as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. Net present value is determined as of the end of each fiscal year and reflects the present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (such cash flows are adjusted to reflect the impact of hedges, our lenders’ commodity price forecasts, and, if necessary, to include only a portion of our reserves that are not proved developed producing reserves). Additionally, the ratio of debt to capitalization (defined as net worth plus debt) will not be permitted to be greater than 60%. We were in compliance with our debt covenant ratios as of December 31, 2013. Investment Grade Date means the first date on which our long-term senior unsecured debt ratings are BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness, make investments, loans or advances and enter into certain hedging agreements; our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person, enter into certain affiliate transactions, make certain distributions during the continuation of an event of default and allow material changes in the nature of our business. In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors.
The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.
Letters of Credit
In addition to the Notes and Credit Facility Agreement, WPX has entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2013 a total of $361 million in letters of credit have been issued.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Apco
Apco had a loan agreement with a financial institution for a $10 million bank line of credit. As of December 31, 2013, Apco had borrowed $8 million under this banking agreement. Principal amounts will be repaid in installments through 2016. This debt agreement contains covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, purchase or sell assets outside the ordinary course of business, and incur additional debt.
Note 10. Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes:
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Significant components of deferred tax liabilities and deferred tax assets are as follows:
Net cash refunds for domestic income taxes were $26 million in 2013 while net cash payments were $40 million and $10 million in 2012 and 2011, respectively. Additionally, payments made directly to foreign taxing authorities were $14 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
As of December 31, 2013, the Company has approximately $114 million of federal net operating loss ("NOL") carryovers which begin expiring after 2033, as well as approximately $825 million of state NOL carryovers, primarily in Pennsylvania, of which more than 90 percent expire after 2029.
Income (loss) from continuing operations before income taxes includes foreign income of $50 million, $52 million and $40 million in 2013, 2012 and 2011, respectively. This income is attributable to our 69 percent investment in Apco, a Cayman Islands corporation with operations in Argentina and Colombia. The statutory income tax rate in Argentina is 35 percent while the rate in Colombia is 25 percent with an additional 9 percent for certain items.
We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania and Apco's operations in Colombia. In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. Apco has historically generated NOLs from its Colombia operations. As a result of our assessment of available evidence, valuation allowances were recorded to reduce recognized tax assets, net of federal benefit, to an amount that will more likely than not be realized by the Company.
Undistributed earnings of Apco at December 31, 2013, excluding amounts related to Apco's equity investment in Petrolera Entre Lomas S.A. ("Petrolera") totaled approximately $76 million. No provision for deferred U.S. income taxes has been made for those undistributed earnings because it is our intent to reinvest Apco's earnings in its operation in Argentina and Colombia. U.S income taxes have been accrued as required by GAAP, however, to the extent book basis exceeds tax basis in Apco's equity investment in Petrolera.
In September 2013, the Argentine government enacted tax reform legislation related to dividends and capital gains which will apply to the Argentine operations of Apco. The new 10 percent dividend tax will be accrued by Apco when dividends are paid by its Argentine investments in future periods. The capital gains tax applies to the sale of Argentine securities by a non-Argentine resident, such as Apco, making such sales subject to an effective 13.5 percent tax on the gross proceeds. As a result, Apco recorded approximately $14 million of foreign deferred tax expense during third quarter 2013 for the excess book basis over tax basis in its equity investment in Petrolera, of which approximately $12 million relates to basis differences that occurred prior to 2013. This accrual was partially offset by approximately $4 million of U.S. deferred tax benefit recorded by WPX related to the additional Argentine tax.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the additional tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. Since the additional tax benefit does not reduce our current taxes payable for 2013, these tax benefits are not included in the Company’s loss carryovers deferred tax asset. The additional tax benefit deductible for tax purposes but not included in our loss carryovers deferred tax asset as of December 31, 2013 totaled $7 million.
Through the effective date of the spin-off, December 31, 2011, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for 2011 has been calculated on a separate return basis for the Company and its consolidated subsidiaries, except for certain adjustments such as alternative minimum tax calculated at the consolidated level by Williams. Effective with the spin-off, Williams and the Company entered into a tax sharing agreement which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off.
In connection with the spin-off, alternative minimum tax credits were estimated and allocated between Williams and the Company effective December 31, 2011. This resulted in the allocation to the Company of a $98 million deferred tax asset with a corresponding increase to additional paid-in-capital. Subsequent to the spin-off, Williams notified the Company of certain corrections that resulted in $15 million of reductions in the alternative minimum tax credit allocated to the Company of which $11 million is a reduction of the benefit for income taxes in 2012.
Pursuant to our tax sharing agreement with Williams, we will remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. During the third quarter of 2012, Williams finalized settlements with the IRS for 2009 and 2010. We were recently notified that the IRS has commenced an audit of Williams' 2011 consolidated tax filing. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for Apco's operations in Argentina are open to audit for the 2006 to 2013 tax years.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
As of December 31, 2013, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of an unrecognized tax benefit.
Note 11. Contingent Liabilities and Commitments
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs' proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We are in the process of conducting an accounting under that standard. However, we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law.
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraud, fraud concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR's guidance provides its view as to how much of a producer's bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR's assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR's predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2007 through December 2013, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $106 million.
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending or threatened litigation described below relating to the 2000-2001 California energy crisis and the reporting of certain natural gas-related information to trade publications.
California energy crisis
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (“FERC”). We have entered into settlements with the State of California (“State Settlement”), major California utilities (“Utilities Settlement”) and others that substantially resolved each of these issues with these parties.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We currently have a settlement agreement in principle with certain California utilities aimed at eliminating and substantially reducing this exposure. Once finalized, the settlement agreement will also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement will resolve most, if not all, of our legal issues arising from the 2000-2001 California energy crisis. With respect to these matters, amounts accrued are not material to our financial position.
Certain other issues also remain open at the FERC and for other nonsettling parties.
Reporting of natural gas-related information to trade publications
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion on the Western States Antitrust Litigation. The panel held that the Natural Gas Act does not preempt the plaintiffs' state antitrust claims, reversing the summary judgment entered in favor of the defendants. The panel further held that the district court did not abuse its discretion in denying the plaintiffs' motions for leave to amend complaints. Defendants' filed a petition for writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
At December 31, 2013, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of December 31, 2013 and December 31, 2012, the Company had accrued approximately $16 million and $18 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In 2013, we accrued and settled certain royalty litigation matters for approximately $8 million. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Commitments
As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2013 are as follows:
We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services and well completion services, which total $389 million over approximately six years.
We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in November 2014.
In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2013, are payable as follows:
Total rent expense, excluding amounts capitalized, was $27 million, $20 million and $12 million in 2013, 2012 and 2011, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
Note 12. Employee Benefit Plans
Subsequent to spin-off
On January 1, 2012, several new plans became effective for us including a defined contribution plan. WPX matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $16 million and $6 million for 2013 and 2012, respectively. Approximately $11 million and $10 million were included in accrued and other current liabilities at December 31, 2013 and December 31, 2012, respectively, related to the non-matching annual employer contribution.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Prior to spin-off
Through the spin-off date, certain benefit costs associated with direct employees who supported our operations were determined based on a specific employee basis and were charged to us by Williams as described below. These pension and post retirement benefit costs included amounts associated with vested participants who are no longer employees. As described in Note 3, Williams also charged us for the allocated cost of certain indirect employees of Williams who provided general and administrative services on our behalf. Williams included an allocation of the benefit costs associated with these Williams employees based upon Williams’ determined benefit rate, not necessarily specific to the employees providing general and administrative services on our behalf. As a result, the information described below is limited to amounts associated with the direct employees that supported our operations.
For the periods presented, we were not the plan sponsor for these plans. Accordingly, our Consolidated Balance Sheets do not reflect any assets or liabilities related to these plans.
Pension plans
Williams is the sponsor of noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2011 totaled $8 million.
Other postretirement benefits
Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (“other postretirement benefits”) that provide benefits to certain eligible participants, generally including employees hired on or before December 31, 1991, and other miscellaneous defined participant groups. Other postretirement benefit expense charged to us by Williams for 2011 totaled less than $1 million.
Defined contribution plan
Williams also is the sponsor of a defined contribution plan that provides benefits to certain eligible participants and charged us compensation expense of $4 million in 2011 for Williams’ matching contributions to this plan.
Note 13. Stock-Based Compensation
WPX Energy, Inc. 2011 Incentive Plan
Subsequent to the spin-off, we have an equity incentive plan (“2011 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2011 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2011 Incentive Plan is 11 million shares. The 2011 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2011 Incentive Plan.
The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 117 thousand shares at an average price of $14.33 per share during 2013.
The Williams Companies, Inc. Incentive Plan
Certain of our direct employees participated in The Williams Companies, Inc. 2007 Incentive Plan, which provides for Williams common-stock-based awards to both employees and Williams’ nonmanagement directors. The plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets.
Through the date of spin-off, we were charged by Williams for stock-based compensation expense related to our direct employees. Williams also charged us for the allocated costs of certain indirect employees of Williams (including stock-based compensation) who provided general and administrative services on our behalf. However, information included in this note is
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
limited to stock-based compensation associated with the direct employees for 2011. See Note 3 for total costs charged to us by Williams.
Williams’ Compensation Committee determined that all outstanding Williams stock-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (the “Pre-2006 Options”), be converted into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options (whether held by our employees or other Williams employees) converted into options for both Williams and WPX common stock following the spin-off, in the same ratio as is used in the distribution of WPX common stock to holders of Williams common stock. The number of shares underlying each such award (including the Pre-2006 Options) and, with respect to options (including the Pre-2006 Options), the per share exercise price of each award was adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of each award.
Employee stock-based awards
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at fair value on the grant date and generally vest over three years . Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Total stock-based compensation expense (including amount charged to us by Williams) reflected in general and administrative expense for the years ended December 31, 2013, 2012 and 2011 was $31 million, $28 million and $18 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2013 was $41 million. This amount is comprised of $1 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 2.0 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2013.
__________
(a)
Includes approximately 344 thousand shares held by Williams’ employees at a weighted average price of $9.24 per share at December 31, 2013 and 598 thousand shares held by Williams' employees at a weighted average price of $8.48 per share at December 31, 2012.
The total intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $5 million, $5 million and $7 million, respectively.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2013.
The estimated fair value at date of grant of options for our common stock and date of conversion for WPX awards in each respective year, using the Black-Scholes option pricing model, is as follows:
For 2013 and 2012, we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method.
For 2011, the weighted average fair value is a component of the intrinsic value calculation at spin-off. The expected volatility yield is based on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the modification date. The expected life of the options is based over the remaining option term.
Cash received from stock option exercises was $4 million and $2 million during 2013 and 2012, respectively.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2013.
__________
(a)
Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other restricted stock unit information
Performance-based shares granted represent 17 percent of nonvested restricted stock units outstanding at December 31, 2013. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
Note 14. Stockholders’ Equity
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends were declared or paid for 2013, 2012 or 2011. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.
Note 15. Fair Value Measurements
Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
•
Level 1-Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
•
Level 2-Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps, and options. These options, which hedge future sales of production, are structured as costless collars or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.
•
Level 3-Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
__________
(a)
The carrying value of total debt, excluding capital leases, was $1,918 million and $1,508 million as of December 31, 2013 and 2012, respectively.
Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2013, consist primarily of natural gas index transactions that are used to manage our physical requirements.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2013 or 2012. During the period ended March 31, 2011, certain NGL swaps that originated during the first quarter of 2011 were transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3 due to a lack of observable third-party market quotes. Due to an increase in exchange-traded transactions and greater visibility from OTC trading, we transferred these instruments to Level 2.
The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations.
For the year ending December 31, 2011, the entire $12 million reduction to level 3 fair value measurements are settlements.
As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, future natural gas liquids prices, expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In each of the three years ended December 31, 2013, our assessments identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
__________
(a)
As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million
•
$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
•
$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.
•
$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
•
$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
•
$85 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
(b)
As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.
•
$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
•
$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
(c)
As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.
•
$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
•
$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
Note 16. Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.
We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.
The following table sets forth the derivative notional volumes that are economic hedges of production volumes as well as notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, both which are included in our commodity derivatives portfolio as of December 31, 2013.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Derivatives related to production
Derivatives primarily related to storage and transportation
__________
(a)
Derivatives related to crude oil production are business day average swaps, basis swaps, and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
(b)
Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon.
(d)
WPX Marketing enters into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(e)
WPX Marketing transacts at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
(f)
The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.
Fair values and gains (losses)
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (“AOCI”) or revenues.
__________
(a)
Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of December 31, 2013, we had collateral totaling $71 million posted to derivative counterparties, which includes $19 million of initial margin to clearinghouses or exchanges to enter into positions and $52 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $72 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2012, we had collateral totaling $2 million posted to derivative counterparties to support the aggregate fair value of our net $5 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $20 million and $3 million at December 31, 2013 and December 31, 2012, respectively.
Cash flow hedges
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark to market value. As of December 31, 2012, we had hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) were reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Actual
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
gains or losses realized in the first quarter of 2013 matched these values. These gains substantially offset net losses that were realized in earnings from previous unfavorable market movements associated with underlying hedged transactions.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:
Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2013, 2012 and 2011, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
The gross and net credit exposure from our derivative contracts as of December 31, 2013, is summarized as follows:
__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
Our three largest net counterparty positions represent approximately 89 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
Other
At December 31, 2013, we held collateral support of approximately $55 million, either in the form of cash or letters of credit, related to our gas management sale agreements.
Revenues
During 2013, 2012, and 2011, BP Energy Company, a domestic segment customer, accounted for 15 percent, 10 percent and 11 percent of our consolidated revenues, respectively. During 2013, Southern California Gas Company accounted for 11 percent of our consolidated revenues. Williams accounted for 8 percent and 12 percent of our consolidated revenue for 2013 and 2012 respectively. Prior to 2012, Williams was considered an affiliate of WPX. See Note 3 for revenue related to Williams for 2011. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
Note 17. Segment Disclosures
Our reporting segments are domestic and international (see Note 1).
Our segment presentation is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions. Domestic and international maintain separate capital and cash management structures. These factors, coupled with differences in the business environment associated with operating in different countries, serve to differentiate the management of this entity as a whole.
Performance Measurement
We evaluate performance based upon segment revenues and segment operating income (loss). There are no intersegment sales between domestic and international.
The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statements of Operations. Long-lived assets are comprised of gross property, plant and equipment and long-term investments.
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
WPX Energy, Inc.
Notes to Consolidated Financial Statements-(Continued)
WPX Energy, Inc.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows:
The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.
Net loss for fourth-quarter 2013 includes the following pre-tax items:
•
$1,373 million of impairments of costs of producing properties, acquired unproved reserves, leasehold and equity method investment (see Note 4 and Note 6).
•
$36 million gain on the sale of deep rights in the Powder River Basin.
•
$9 million buyout of a transportation agreement.
Net loss for third-quarter 2013 includes the following pre-tax items:
•
$19 million of impairments of costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin (see Note 6).
•
$7 million accrual for litigation.
Net loss for fourth-quarter 2012 includes the following pre-tax items:
•
$108 million of impairments of producing properties and costs of acquired unproved reserves (see Note 6).
Net loss for second-quarter 2012 includes the following pre-tax items:
•
$65 million of impairments of costs of acquired unproved reserves in the Powder River Basin (see Note 6).
•
Gain on sale of Barnett and Arkoma properties.
Net loss for first-quarter 2012 includes the following pre-tax items:
•
$52 million of impairments of costs of acquired unproved reserves primarily in the Powder River Basin (see Note 6).
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures
(Unaudited)
We have significant oil and gas producing activities primarily in the Piceance and San Juan Basins in the Rocky Mountain region, the Williston Basin in North Dakota and the Appalachian Basin in Pennsylvania, all of which are located in the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. The following information excludes our gas management activities.
With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information, through the date of sale in 2012, for the holdings in the Barnett Shale and Arkoma Basin which have been reported as discontinued operations in our consolidated financial statements. These operations represented less than five percent of our total domestic and international proved reserves in 2011.
Capitalized Costs
•
Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $329 million and $365 million, net, for 2013 and 2012, respectively.
•
Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.
•
Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproved reserves.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
Cost Incurred
•
Costs incurred include capitalized and expensed items.
•
Acquisition costs are as follows: The 2013 and 2012 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves. The 2011 costs are primarily for additional leasehold in the Appalachian Basin.
•
Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.
•
Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.
•
We have classified our step-out drilling and site preparation costs in the Powder River Basin as development. While the immediate offsets are frequently in the dewatering stage, the development classification better reflects the low risk profile of the costs incurred.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
Results of Operations
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
•
Amounts for all years exclude the equity earnings (losses) from our equity method investees. Net equity earnings (losses) from these investees were $23 million, $30 million and $24 million in 2013, 2012 and 2011, respectively.
•
Natural gas revenues consist of natural gas production sold and includes realized gains (losses) of derivatives that were designated as cash flow hedges in 2012 and 2011.
•
For derivative instruments that were entered into after January 1, 2012, we did not designate those as cash flow hedges. Any gain (loss) related to these derivatives is included in net gain on derivatives not designated as hedges.
•
Other revenues consist of activities that are an indirect part of the producing activities.
•
Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachia Basin.
•
Depreciation, depletion and amortization includes depreciation of support equipment.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
Proved Reserves
The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
The following is a summary of and changes in our domestic and international proved reserves. Our international reserves are primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest. The Entity’s share of equity method investee represents Apco’s 40.8 percent interest in reserves of Petrolera Entre Lomas S.A.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
__________
(a)
Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
•
Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
•
The domestic revisions in 2013 reflects 133 Bcfe related to developed reserves and 44 Bcfe related to undeveloped reserves. The domestic revisions in 2012 primarily resulted from the lower 12-month average price as compared to the 12-month average price used in 2011. The domestic revisions in 2011 primarily relate to the reclassification of reserves from proved to probable reserves attributable to locations not expected to be developed within five years.
•
Divestitures in 2012 primarily relate to the sale in 2012 of our holdings in the Barnett Shale and the Arkoma Basin (see Note 2 of Notes to Consolidated Financial Statements).
•
Domestic extensions and discoveries in 2013 reflects 127 Bcfe added for drilled locations and 407 Bcfe added for new undeveloped locations. The 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin. Domestic extensions and discoveries in 2012 reflect 225 Bcfe added for drilled locations and 405 Bcfe added for new undeveloped locations. The 2012 extensions and discoveries were primarily in the Williston Basin, Appalachian Basin and Piceance Basin. Domestic extensions and discoveries in 2011 reflect 306 Bcfe added for drilled locations and 760 Bcfe added for new undeveloped locations. The 2011 extensions and discoveries were primarily in the Piceance Basin, Appalachian Basin and Williston Basin.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves. Prices are based on the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years ended December 31, 2013, 2012 and 2011, the average domestic combined natural gas and NGL equivalent price was $3.63, $3.01 and $4.41 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2013, 2012 and 2011 was $92.16, $82.32 and $86.87 per barrel, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows
__________
(a)
Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
(b)
Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.
WPX Energy, Inc.
Supplemental Oil and Gas Disclosures-(Continued)
(Unaudited)
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
__________
(a)
Amounts primarily attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
(b)
Represents Apco’s 40.8 percent interest in Petrolera Entre Lomas S.A.
WPX Energy, Inc.
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
__________
(a)
Deducted from related assets.
(b)
Deferred tax asset retained by Williams.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Disclosure Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Fourth Quarter 2013 Changes in Internal Controls
There have been no changes during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
The information called for by this Item 10 is incorporated by reference to our definitive proxy statement for our 2014 Annual meeting of Stockholders, or our 2014 Proxy Statement, anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, under the headings “Proposal 1- Election of Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership and Reporting Compliance.”
The information called for by this Item 11
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated by reference to our 2014 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, under the headings “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.”
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated by reference to our 2014 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, under the headings “Corporate Governance” and “Certain Relationships and Transactions.”
Item 14.
Item 14.
Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated by reference to our 2014 Proxy Statement anticipated to be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, under the heading “Independent Registered Public Accounting Firm.”
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a) 1 and 2.
(a) 3 and (b). The exhibits listed below are filed as part of this annual report.
INDEX TO EXHIBITS
#
Certain portions have been omitted pursuant to an Order Granting Confidential Treatment issued by the SEC on December 5, 2011. Omitted information has been filed separately with the SEC.
*
Filed herewith
**
Furnished herewith
(1)
Management contract or compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WPX ENERGY, Inc.
(Registrant)
By:
/s/ J. Kevin Vann
J. Kevin Vann
Controller
Date: February 27, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.