The intrinsic value of restricted stock awards vested during the years ended December 31, 2016, 2015 and 2014 was $25 million, $31 million and $17 million, respectively.
Restricted stock awards made to employees have vesting periods ranging from 1 year with variable vesting dates to 10 years.
Following is a summary of the future vesting of our outstanding restricted stock awards:
## Table 0 ##
The related compensation costs less estimated forfeitures is generally recognized ratably over the vesting period of the restricted stock awards.
Upon vesting, the grants will be paid in our Class P common shares.
During 2016, 2015 and 2014, we recorded $66 million, $52 million and $51 million, respectively, in expense related to restricted stock awards and capitalized approximately $9 million, $15 million and $6 million, respectively.
At December 31, 2016 and 2015, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $133 million and $154 million, respectively.
Pension and Other Postretirement Benefit Plans Savings Plan We maintain a defined contribution plan covering eligible U. S.  employees.
We contribute 5% of eligible compensation for most of the plan participants.
Certain plan participants’ contributions and Company contributions are based on collective bargaining agreements.
The total expense for our savings plan was approximately $48 million, $46 million, and $42 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Pension Plans Our U. S.  pension plan is a defined benefit plan that covers substantially all of our U. S.  employees and provides benefits under a cash balance formula.
A participant in the cash balance plan accrues benefits through contribution credits based on a combination of age and years of service, times eligible compensation.
Interest is also credited to the participant’s plan account.
A participant becomes fully vested in the plan after three years, and may take a lump sum distribution upon termination of employment or retirement.
Certain collectively bargained and grandfathered employees continue to accrue benefits through career pay or final pay formulas.
Two of our subsidiaries, Kinder Morgan Canada Inc.  and Trans Mountain Pipeline Inc.  (as general partner of Trans Mountain Pipeline L. P. ), are sponsors of pension plans for eligible Canadian and Trans Mountain pipeline employees.
The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits) and defined contributory plans.
Benefits under the defined benefit components accrue through career pay or final pay formulas.
The net periodic benefit costs, contributions and liability amounts associated with our Canadian plans are not material to our consolidated income statements or balance sheets; however, we began to include the activity and balances associated with our Canadian plans (including our Canadian OPEB plans discussed below) in the following disclosures on a prospective basis beginning in 2016.
The associated net periodic benefit costs for these combined Canadian plans of $12 million and $10 million for the years ended December 31, 2015 and 2014, respectively, were reported separately in prior years.
Other Postretirement Benefit Plans We and certain of our U. S.  subsidiaries provide other postretirement benefits (OPEB), including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees.
Our Canadian subsidiaries also provide OPEB benefits to current and future retirees and their dependents.
Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar
had no accrued penalties as of both December 31, 2017 and 2016 and $2 million in accrued penalties as of December 31, 2015.
All of the $97 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods.
In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $6 million during the next year to approximately $91 million, primarily due to lapses in statute of limitations partially offset by additions for state filing positions taken in prior years.
We are subject to taxation, and have tax years open to examination for the periods 2011-2016 in the U. S. , 2005-2016 in various states and 2007-2016 in various foreign jurisdictions.
Impact of 2017 Tax Reform On December 22, 2017, the U. S.  enacted the 2017 Tax Reform.
Among the many provisions included in the 2017 Tax Reform is a provision to reduce the U. S.  federal corporate income tax rate from 35% to 21% effective January 1, 2018.
As of December 31, 2017, we had deferred tax assets related to our net operating loss carryforwards and tax credits, in addition to tax basis in excess of accounting basis primarily related to our investment in KMP.
Prior to the 2017 Tax Reform, the value of these deferred tax assets was recorded at the previous income tax rate of 35%, which represented their expected future benefit to us.
As a result of the 2017 Tax Reform, the future benefit of these deferred tax assets was re-measured at the new income tax rate of 21% and we recorded an approximate $1,240 million provisional non-cash adjustment for the year ended December 31, 2017.
We determined the effects of the rate change using our best estimate of temporary book-to-tax differences.
Upon final analysis and remeasurement of our deferred tax balances, the December 31, 2017 adjustment we recorded to reflect the change in corporate income tax rates may need to be adjusted in subsequent periods.
In addition, the 2017 Tax Reform will require a mandatory deemed repatriation of post-1986 undistributed foreign earnings and profits.
As of December 31, 2017, we have recorded a provisional amount for this 2017 Tax Reform provision and we are continuing to finalize earnings and profits used in this calculation as well assess other 2017 Tax Reform impacts to complete our analysis on this provision.
However, we do not expect this provision of the 2017 Tax Reform to be material to us.
The income tax rate change in the 2017 Tax Reform had an impact not only on our corporate income taxes but also resulted in us recording an approximate $144 million after-tax ($219 million pre-tax) provisional non-cash adjustment, including our share of equity investee provisional adjustments, related to our FERC regulated business for the year ended December 31, 2017.
We have determined a reasonable estimate of its impact and recorded a provisional regulatory reserve as of December 31, 2017.
However, as the impact on the regulatory rate making process is currently uncertain, we have not completed our assessment of the 2017 Tax Reform’s effect on our FERC regulated business.
As described above, we continue to assess the impact of the 2017 Tax Reform on our business in order to complete our analysis.
Any adjustment to our provisional amounts will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made.6.
Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2017 and 2016, our property, plant and equipment, net consisted of the following (in millions):
## Table 1 ##
## Table 2 ##
(a) We operate Ruby and own the common interest in Ruby.
Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest.
If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.
Competition The market for supply of natural gas is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines segment.
Our operations compete with interstate and intrastate pipelines, and their shippers, for connections to new markets and supplies and for transportation, processing and treating services.
We believe the principal elements of competition in our various markets are location, rates, terms of service and flexibility and reliability of service.
From time to time, other projects are proposed that would compete with us.
We do not know whether or when any such projects would be built, or the extent of their impact on our operations or profitability.
Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane, fuel oils and renewables such as wind and solar.
Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.
CO2 Our CO2 business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields.
Our CO2 pipelines and related assets allow us to market a complete
(c) Effective January 1, 2019, these assets were transferred from the Products Pipelines business segment to the Natural Gas Pipelines business segment.
(d) Effective January 1, 2019, a small number of terminals were transferred between the Products Pipelines and Terminals business segments.
Competition Our Products Pipelines’ pipeline operations compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars.
Our Products Pipelines’ terminal operations compete with proprietary terminals owned and operated by major oil companies and other independent terminal operators, and our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.
Terminals Our Terminals business segment includes the operations of our refined petroleum product, crude oil, chemical, ethanol and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our petroleum coke, metal and ores facilities.
Our terminals are located throughout the U. S.  and in portions of Canada.
We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities.
We often classify our terminal operations based on the handling of either liquids or dry-bulk material products.
In addition, Terminals’ marine operations include Jones Act-qualified product tankers that provide marine transportation of crude oil, condensate and refined petroleum products between U. S.  ports.
The following summarizes our Terminals business segment assets, as of December 31, 2018:

<table><tr><td>Year</td><td>Vesting of Restricted Shares</td></tr><tr><td>2017</td><td>1,476,832</td></tr><tr><td>2018</td><td>2,352,443</td></tr><tr><td>2019</td><td>4,358,728</td></tr><tr><td>2020</td><td>539,790</td></tr><tr><td>2021</td><td>199,850</td></tr><tr><td>Thereafter</td><td>110,494</td></tr><tr><td>Total Outstanding</td><td>9,038,137</td></tr></table>
<table><tr><td></td><td colspan="2">December 31,</td></tr><tr><td></td><td>2017</td><td>2016</td></tr><tr><td>Pipelines (Natural gas, liquids, crude oil and CO<sub>2</sub>)</td><td>$20,157</td><td>$19,341</td></tr><tr><td>Equipment (Natural gas, liquids, crude oil, CO<sub>2</sub>, and terminals)</td><td>24,152</td><td>23,298</td></tr><tr><td>Other(a)</td><td>5,570</td><td>4,780</td></tr><tr><td>Accumulated depreciation, depletion and amortization</td><td>-14,175</td><td>-12,306</td></tr><tr><td></td><td>35,704</td><td>35,113</td></tr><tr><td>Land and land rights-of-way</td><td>1,456</td><td>1,431</td></tr><tr><td>Construction work in process</td><td>2,995</td><td>2,161</td></tr><tr><td>Property, plant and equipment, net</td><td>$40,155</td><td>$38,705</td></tr></table>
<table><tr><td>Asset (KMI ownership shown if not 100%)</td><td>MilesofPipeline</td><td>Design (Bcf/d) Capacity</td><td>Storage (Bcf) [Processing (Bcf/d)] Capacity</td><td>Supply and Market Region</td></tr><tr><td>EagleHawk -25%</td><td>530</td><td>1.20</td><td>—</td><td>South Texas, Eagle Ford shale formation</td></tr><tr><td>KM Altamont</td><td>1,380</td><td>0.08</td><td>[0.08]</td><td>Utah, Uinta Basin</td></tr><tr><td>Red Cedar -49%</td><td>900</td><td>0.70</td><td>—</td><td>La Plata County, Colorado, Ignacio Blanco Field</td></tr><tr><td>Rocky Mountain</td><td></td><td></td><td></td><td></td></tr><tr><td>Fort Union -37%</td><td>310</td><td>1.25</td><td>—</td><td>Powder River Basin (Wyoming)</td></tr><tr><td>Bighorn -51%</td><td>290</td><td>0.60</td><td>—</td><td>Powder River Basin (Wyoming)</td></tr><tr><td>KinderHawk</td><td>510</td><td>2.00</td><td>—</td><td>Northwest Louisiana, Haynesville and Bossier shale formations</td></tr><tr><td>North Texas</td><td>550</td><td>0.14</td><td>[0.10]</td><td>North Barnett Shale Combo</td></tr><tr><td>Endeavor -40%</td><td>101</td><td>0.15</td><td>—</td><td>East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale</td></tr><tr><td>Camino Real</td><td>70</td><td>0.15</td><td>—</td><td>South Texas, Eagle Ford shale formation</td></tr><tr><td>KM Treating</td><td>—</td><td>—</td><td>—</td><td>Odessa, Texas, other locations in Tyler and Victoria, Texas</td></tr><tr><td>Hiland - Williston</td><td>2,030</td><td>.32</td><td>[0.20]</td><td>Bakken/Three Forks shale formations (North Dakota/Montana)</td></tr><tr><td colspan="5">Midstream Liquids/Oil/Condensate Pipelines</td></tr><tr><td></td><td></td><td>(MBbl/d)</td><td>(MBbl)</td><td></td></tr><tr><td>Liberty Pipeline -50%</td><td>87</td><td>140</td><td>—</td><td>Y-grade pipeline from Houston Central complex to the Texas Gulf Coast</td></tr><tr><td>South Texas NGL Pipelines</td><td>340</td><td>115</td><td>—</td><td>Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast</td></tr><tr><td>Camino Real - Condensate</td><td>69</td><td>110</td><td>60</td><td>South Texas, Eagle Ford shale formation</td></tr><tr><td>Hiland - Williston - Oil</td><td>1,500</td><td>282</td><td>—</td><td>Bakken/Three Forks shale formations (North Dakota/Montana)</td></tr><tr><td>EagleHawk - Condensate -25%</td><td>400</td><td>220</td><td>60</td><td>South Texas, Eagle Ford shale formation</td></tr></table>

Question: What was the total amount of (MBbl/d) for Midstream Liquids/Oil/Condensate Pipelines?
Answer: 867.0